Illinois 2025-2026 Regular Session

Illinois House Bill HB3779 Compare Versions

Only one version of the bill is available at this time.

Old	New	Differences
1	1	104TH GENERAL ASSEMBLY State of Illinois 2025 and 2026 HB3779 Introduced , by Rep. Ann M. Williams SYNOPSIS AS INTRODUCED: See Index Creates the Municipal and Cooperative Electric Utility Planning and Transparency Act. Provides that, by November 1, 2025, and by November 1 every 3 years thereafter, all electric cooperatives with members in the State, municipal power agencies, and municipalities shall file with the Illinois Power Agency an integrated resource plan. Sets forth provisions concerning the plan. Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to develop capacity procurement plans and conduct competitive procurement processes for the procurement of capacity needed to ensure environmentally sustainable long-term resource adequacy across the State at the lowest cost over time. Amends the Public Utilities Act. Changes the cumulative persisting annual savings goals for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers for the years of 2025 through 2030. Provides that the cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 (rather than 0.6) percentage points per year. Changes the requirements for submitting proposed plans and funding levels to meet savings goals for an electric utility serving more than 500,000 retail customers (rather than serving less than 3,000,000 retail customers but more than 500,000 retail customers). Provides that an electric utility that has a tariff approved within one year of the amendatory Act shall also offer at least one market-based, time-of-use rate for eligible retail customers that choose to take power and energy supply service from the utility. Sets forth provisions regarding the Illinois Commerce Commission's powers and duties related to residential time-of-use pricing. Provides that each capacity procurement event may include the procurement of capacity through a mix of contracts with different terms and different initial delivery dates. Sets forth the requirements of prepared capacity procurement plans. Requires each alternative electric supplier to make payment to an applicable electric utility for capacity, receive transfers of capacity credits, report capacity credits procured on its behalf to the applicable regional transmission organization, and submit the capacity credits to the applicable regional transmission organization under that regional transmission organization's rules and procedures. Makes other changes. LRB104 11172 AAS 21254 b A BILL FOR 104TH GENERAL ASSEMBLY State of Illinois 2025 and 2026 HB3779 Introduced , by Rep. Ann M. Williams SYNOPSIS AS INTRODUCED: See Index See Index Creates the Municipal and Cooperative Electric Utility Planning and Transparency Act. Provides that, by November 1, 2025, and by November 1 every 3 years thereafter, all electric cooperatives with members in the State, municipal power agencies, and municipalities shall file with the Illinois Power Agency an integrated resource plan. Sets forth provisions concerning the plan. Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to develop capacity procurement plans and conduct competitive procurement processes for the procurement of capacity needed to ensure environmentally sustainable long-term resource adequacy across the State at the lowest cost over time. Amends the Public Utilities Act. Changes the cumulative persisting annual savings goals for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers for the years of 2025 through 2030. Provides that the cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 (rather than 0.6) percentage points per year. Changes the requirements for submitting proposed plans and funding levels to meet savings goals for an electric utility serving more than 500,000 retail customers (rather than serving less than 3,000,000 retail customers but more than 500,000 retail customers). Provides that an electric utility that has a tariff approved within one year of the amendatory Act shall also offer at least one market-based, time-of-use rate for eligible retail customers that choose to take power and energy supply service from the utility. Sets forth provisions regarding the Illinois Commerce Commission's powers and duties related to residential time-of-use pricing. Provides that each capacity procurement event may include the procurement of capacity through a mix of contracts with different terms and different initial delivery dates. Sets forth the requirements of prepared capacity procurement plans. Requires each alternative electric supplier to make payment to an applicable electric utility for capacity, receive transfers of capacity credits, report capacity credits procured on its behalf to the applicable regional transmission organization, and submit the capacity credits to the applicable regional transmission organization under that regional transmission organization's rules and procedures. Makes other changes. LRB104 11172 AAS 21254 b LRB104 11172 AAS 21254 b A BILL FOR
2	2	104TH GENERAL ASSEMBLY State of Illinois 2025 and 2026 HB3779 Introduced , by Rep. Ann M. Williams SYNOPSIS AS INTRODUCED:
3	3	See Index See Index
4	4	See Index
5	5	Creates the Municipal and Cooperative Electric Utility Planning and Transparency Act. Provides that, by November 1, 2025, and by November 1 every 3 years thereafter, all electric cooperatives with members in the State, municipal power agencies, and municipalities shall file with the Illinois Power Agency an integrated resource plan. Sets forth provisions concerning the plan. Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to develop capacity procurement plans and conduct competitive procurement processes for the procurement of capacity needed to ensure environmentally sustainable long-term resource adequacy across the State at the lowest cost over time. Amends the Public Utilities Act. Changes the cumulative persisting annual savings goals for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers for the years of 2025 through 2030. Provides that the cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 (rather than 0.6) percentage points per year. Changes the requirements for submitting proposed plans and funding levels to meet savings goals for an electric utility serving more than 500,000 retail customers (rather than serving less than 3,000,000 retail customers but more than 500,000 retail customers). Provides that an electric utility that has a tariff approved within one year of the amendatory Act shall also offer at least one market-based, time-of-use rate for eligible retail customers that choose to take power and energy supply service from the utility. Sets forth provisions regarding the Illinois Commerce Commission's powers and duties related to residential time-of-use pricing. Provides that each capacity procurement event may include the procurement of capacity through a mix of contracts with different terms and different initial delivery dates. Sets forth the requirements of prepared capacity procurement plans. Requires each alternative electric supplier to make payment to an applicable electric utility for capacity, receive transfers of capacity credits, report capacity credits procured on its behalf to the applicable regional transmission organization, and submit the capacity credits to the applicable regional transmission organization under that regional transmission organization's rules and procedures. Makes other changes.
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11	11	1 AN ACT concerning regulation.
12	12	2 Be it enacted by the People of the State of Illinois,
13	13	3 represented in the General Assembly:
14	14	4 Section 1. Short title. This Act may be cited as the
15	15	5 Municipal and Cooperative Electric Utility Planning and
16	16	6 Transparency Act.
17	17	7 Section 5. Legislative findings and objectives. The
18	18	8 General Assembly finds:
19	19	9 (1) Municipal and cooperative electric utilities
20	20	10 provide electricity to more than 1,000,000 State
21	21	11 residents.
22	22	12 (2) These utilities are managed by elected officials,
23	23	13 elected board members, or their appointees. Due to their
24	24	14 governance structures, municipal and cooperative electric
25	25	15 utilities are exempt from certain regulatory requirements
26	26	16 and oversight under State and federal law.
27	27	17 (3) State residents who are served by these utilities,
28	28	18 and who pay rates for electricity set by these utilities,
29	29	19 often lack access to important information about these
30	30	20 utilities' generation portfolios, procurement, management
31	31	21 practices, and budgets. Because democratic elections by
32	32	22 member-ratepayers or customers are the ultimate guarantor
33	33	23 of the integrity and cost-effectiveness of these
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37	37	104TH GENERAL ASSEMBLY State of Illinois 2025 and 2026 HB3779 Introduced , by Rep. Ann M. Williams SYNOPSIS AS INTRODUCED:
38	38	See Index See Index
39	39	See Index
40	40	Creates the Municipal and Cooperative Electric Utility Planning and Transparency Act. Provides that, by November 1, 2025, and by November 1 every 3 years thereafter, all electric cooperatives with members in the State, municipal power agencies, and municipalities shall file with the Illinois Power Agency an integrated resource plan. Sets forth provisions concerning the plan. Amends the Illinois Power Agency Act. Authorizes the Illinois Power Agency to develop capacity procurement plans and conduct competitive procurement processes for the procurement of capacity needed to ensure environmentally sustainable long-term resource adequacy across the State at the lowest cost over time. Amends the Public Utilities Act. Changes the cumulative persisting annual savings goals for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers for the years of 2025 through 2030. Provides that the cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 (rather than 0.6) percentage points per year. Changes the requirements for submitting proposed plans and funding levels to meet savings goals for an electric utility serving more than 500,000 retail customers (rather than serving less than 3,000,000 retail customers but more than 500,000 retail customers). Provides that an electric utility that has a tariff approved within one year of the amendatory Act shall also offer at least one market-based, time-of-use rate for eligible retail customers that choose to take power and energy supply service from the utility. Sets forth provisions regarding the Illinois Commerce Commission's powers and duties related to residential time-of-use pricing. Provides that each capacity procurement event may include the procurement of capacity through a mix of contracts with different terms and different initial delivery dates. Sets forth the requirements of prepared capacity procurement plans. Requires each alternative electric supplier to make payment to an applicable electric utility for capacity, receive transfers of capacity credits, report capacity credits procured on its behalf to the applicable regional transmission organization, and submit the capacity credits to the applicable regional transmission organization under that regional transmission organization's rules and procedures. Makes other changes.
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68	68	1 utilities' operations, access to this information is
69	69	2 crucial to ensuring management of these utilities is
70	70	3 prudent and responsive.
71	71	4 (4) Good utility practice entails long-term planning
72	72	5 on the part of a utility, including anticipating
73	73	6 retirement of existing generation resources, planning new
74	74	7 generation build or purchase well in advance of any
75	75	8 capacity shortfall, and developing rigorous estimates of
76	76	9 future load to inform procurement, construction, and
77	77	10 retirement decisions.
78	78	11 (5) In many other states, integrated resource planning
79	79	12 processes have been used to avoid capacity shortfalls,
80	80	13 minimize ratepayer costs, and increase public
81	81	14 participation in and knowledge of electric generation
82	82	15 portfolio choices, even where the planning utility is not
83	83	16 otherwise subject to rate approval by the state.
84	84	17 (6) It is in the best interests of State electricity
85	85	18 customers and member-ratepayers that electricity is
86	86	19 provided by a portfolio of generation and storage
87	87	20 resources and demand-side programs that minimizes both
88	88	21 cost and environmental impacts and that long-term utility
89	89	22 planning can and should facilitate the achievement of such
90	90	23 portfolios.
91	91	24 (7) With the enactment of the Inflation Reduction Act
92	92	25 of 2022, municipal and cooperative electric utilities have
93	93	26 access to a variety of federal funding streams designed to
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104	104	1 facilitate transition from fossil fuel to renewable
105	105	2 generation. Consistent with Congressional intent,
106	106	3 municipal and cooperative electric utilities should
107	107	4 perform a comprehensive analysis of their existing
108	108	5 portfolio and have a duty, as utility managers, to
109	109	6 identify opportunities to minimize member-ratepayer and
110	110	7 customer costs.
111	111	8 (8) To ensure utilities minimize ratepayer costs,
112	112	9 maximize opportunities for transition from fossil fuels to
113	113	10 renewable resources, and to increase transparency and
114	114	11 democratic participation, it is important that municipal
115	115	12 and cooperative electric utilities participate in an
116	116	13 integrated resource planning process with public
117	117	14 participation and Illinois Power Agency oversight.
118	118	15 Section 10. Definitions. As used in this Act:
119	119	16 "Agency" means the Illinois Power Agency.
120	120	17 "Demand-side program" means a program implemented by or on
121	121	18 behalf of a utility to reduce retail customer consumption
122	122	19 (MWh) or shift the time of consumption of energy (MW) from end
123	123	20 users, including energy efficiency programs, demand-response
124	124	21 programs, and programs for the promotion or aggregation of
125	125	22 distributed generation.
126	126	23 "Electric cooperative" has the meaning given to that term
127	127	24 in Section 3-119 of the Public Utilities Act.
128	128	25 "Generation resource" means a facility for the generation
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139	139	1 of electricity.
140	140	2 "Municipal power agency" has the meaning given to that
141	141	3 term in Section 11-119.1-3 of the Illinois Municipal Code.
142	142	4 "Municipality" has the meaning given to that term in
143	143	5 Section 11-119.1-3 of the Illinois Municipal Code.
144	144	6 "Renewable generation resource" means a resource for
145	145	7 generating electricity that uses wind, solar, or geothermal
146	146	8 energy.
147	147	9 "Storage resource" means a commercially available
148	148	10 technology that uses mechanical, chemical, or thermal
149	149	11 processes to store energy and deliver the stored energy as
150	150	12 electricity for use at a later time and is capable of being
151	151	13 controlled by the distribution or transmission entity managing
152	152	14 it, to enable and optimize the safe and reliable operation of
153	153	15 the electric system.
154	154	16 "Utility" means a municipal power agency, municipality, or
155	155	17 electric cooperative.
156	156	18 Section 15. Purpose and contents of integrated resource
157	157	19 plan.
158	158	20 (a) By November 1, 2025, and by November 1 every 3 years
159	159	21 thereafter, all electric cooperatives with members in this
160	160	22 State, municipal power agencies, and municipalities shall file
161	161	23 with the Agency an integrated resource plan, except that
162	162	24 municipalities and electric cooperatives that are members of,
163	163	25 and have a full requirements contract with, a municipal power
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174	174	1 agency or electric cooperative subject to this Act may file a
175	175	2 statement adopting such other utility's integrated resource
176	176	3 plan.
177	177	4 (b) The purposes of the integrated resource plan are to
178	178	5 provide a comprehensive description of the utility's current
179	179	6 portfolio of electrical generation, storage, demand-side
180	180	7 programs, and transmission resources, to forecast future load
181	181	8 changes to facilitate prudent planning with respect to
182	182	9 resource procurement and retirement, to determine what
183	183	10 resource portfolio will meet ratepayers' needs while
184	184	11 minimizing cost and environmental impact, and to articulate
185	185	12 steps the utility will take to reduce customer costs and
186	186	13 environmental impacts through changes to its current
187	187	14 generation portfolio through construction, procurement,
188	188	15 retirement, or demand-side programs.
189	189	16 (c) As part of the integrated resource plan development
190	190	17 process, a utility shall consider all resources reasonably
191	191	18 available or reasonably likely to be available during the
192	192	19 relevant time period to satisfy the demand for electricity
193	193	20 services for a 20-year planning period, taking into account
194	194	21 both supply-side and demand-side electric power resources.
195	195	22 (d) An integrated resource plan shall include, at a
196	196	23 minimum:
197	197	24 (1) A list of all electricity generation facilities
198	198	25 owned by the utility, in whole or in part. For each such
199	199	26 facility, the integrated resource plan shall report:
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210	210	1 (A) general location;
211	211	2 (B) ownership information, if ownership is shared
212	212	3 with another entity;
213	213	4 (C) type of fuel;
214	214	5 (D) the date of commercial operation;
215	215	6 (E) expected useful life;
216	216	7 (F) expected retirement date for any resource
217	217	8 expected to retire within the next 10 years, and an
218	218	9 explanation of the reason for the retirement;
219	219	10 (G) nameplate and peak available capacity;
220	220	11 (H) total MWh generated at the facility during the
221	221	12 previous calendar year;
222	222	13 (I) the date on which the facility is anticipated
223	223	14 to be fully depreciated; and
224	224	15 (J) any compliance obligations, or compliance
225	225	16 obligations expected to apply within the next 10
226	226	17 years, and any proposed or anticipated expenditures
227	227	18 intended to meet those obligations.
228	228	19 (2) A list of all power purchase agreements to which
229	229	20 the utility is a party, whether as purchaser or seller,
230	230	21 including the counterparty, general location and type of
231	231	22 generation resource providing power per the agreement,
232	232	23 date on which the agreement was entered into, duration of
233	233	24 the agreement, and the energy and capacity terms of the
234	234	25 agreement.
235	235	26 (3) A list of any sale transactions of any energy or
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246	246	1 capacity to any purchaser.
247	247	2 (4) A list of any demand-side programs and total
248	248	3 distributed generation.
249	249	4 (5) A narrative description of all existing
250	250	5 transmission facilities owned by the utility, in whole or
251	251	6 in part, that identifies any transmission constraints or
252	252	7 critical contingencies, and identification of the regional
253	253	8 transmission organization, if any, which exercises
254	254	9 operational control over the transmission facility.
255	255	10 (6) A list of all capital expenditures exceeding
256	256	11 $1,000,000 in the previous calendar year that includes a
257	257	12 brief description of the expenditure, the total amount
258	258	13 expended, and whether the expenditure was required to
259	259	14 conform with State or federal law, rule, or regulation;
260	260	15 (7) A description of all transmission costs,
261	261	16 disaggregated by expenditure, that identifies all capital
262	262	17 expenditures on physical infrastructure and contracts for
263	263	18 rights costing greater than $1,000,000 over the term of
264	264	19 the agreement.
265	265	20 (8) A copy of the most recent FERC Form 1 filed by the
266	266	21 utility. If no such FERC Form 1 has been filed, the utility
267	267	22 shall complete a FERC Form 1 for the prior calendar year.
268	268	23 (9) A range of load forecasts for the 5-year planning
269	269	24 period that includes hourly data representing a high-load,
270	270	25 low-load, and expected-load scenario for all retail
271	271	26 customers, consistent with the requirements of paragraph
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282	282	1 (1) of subsection (d) of Section 16-111.5 of the Public
283	283	2 Utilities Act and any associated rules or regulations.
284	284	3 Such forecasts shall include:
285	285	4 (A) all underlying assumptions;
286	286	5 (B) an hourly load analysis consistent with the
287	287	6 requirements of paragraph (1) of subsection (b) of
288	288	7 Section 16-111.5 of the Public Utilities Act;
289	289	8 (C) analysis of the impact of any demand-side
290	290	9 programs, consistent with paragraph (2) of subsection
291	291	10 (b) of Section 16-111.5 of the Public Utilities Act;
292	292	11 (D) any reserve margin or other obligations placed
293	293	12 on the utility by regional transmission organizations
294	294	13 to which it is a member; and
295	295	14 (E) to the extent the information is available, an
296	296	15 assessment of the accuracy of any past load forecasts
297	297	16 submitted pursuant to this Section and an explanation
298	298	17 of any deviation of greater than 10% in either
299	299	18 direction from the forecasted load.
300	300	19 (10) The results of an all-source request for
301	301	20 proposals for generation resources and capacity contracts.
302	302	21 (11) A 5-year action plan for meeting the forecasted
303	303	22 load that minimizes customer cost and adverse
304	304	23 environmental impacts. As part of the action plan, the
305	305	24 utility shall:
306	306	25 (A) Identify any generation or storage resources
307	307	26 anticipated to be removed from service in the 5 years
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318	318	1 following the date on which the integrated resource
319	319	2 plan is submitted.
320	320	3 (B) Determine whether given forecasted load growth
321	321	4 or unit retirements, or both, the utility will need to
322	322	5 procure additional capacity and energy, and provide a
323	323	6 quantitative estimate of any such gap between
324	324	7 forecasted load and supply-side resources.
325	325	8 (C) Provide a narrative description of the
326	326	9 utility's process for evaluating possible resources to
327	327	10 secure this additional capacity and energy.
328	328	11 (D) Provide a narrative description of the
329	329	12 utility's processes for assessing the present economic
330	330	13 value of existing generation and state whether,
331	331	14 consistent with this methodology, any currently
332	332	15 operating units, if any, could be replaced by other
333	333	16 resources at lower cost to ratepayers.
334	334	17 (E) Identify a preferred portfolio of generation,
335	335	18 storage, and demand-side programs that, in the
336	336	19 utility's judgment, meets its forecasted load while
337	337	20 minimizing the ratepayer cost and environmental
338	338	21 impacts to the extent reasonably achievable in the 5
339	339	22 years covered by the action plan. The portfolio shall
340	340	23 incorporate any capacity or other reliability
341	341	24 requirements of any regional transmission organization
342	342	25 of which the utility is a member.
343	343	26 (F) Identify, if the preferred portfolio includes
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354	354	1 the construction of new generation or storage
355	355	2 resources or transmission facilities, the preferred
356	356	3 site for all new construction of generation, storage,
357	357	4 or transmission facilities.
358	358	5 (G) If the utility states that it intends to
359	359	6 remove a generation resource from service, include in
360	360	7 the integrated resource plan a statement describing
361	361	8 the utility's plan to minimize economic impacts to
362	362	9 workers due to facility retirement. This statement
363	363	10 shall include a description of:
364	364	11 (i) the utility's efforts to collaborate with
365	365	12 the workers and their designated representatives,
366	366	13 if any;
367	367	14 (ii) a transition timeline or date certain on
368	368	15 which such a transition timeline shall be made
369	369	16 available to ensure certainty for workers;
370	370	17 (iii) the utility's efforts to protect pension
371	371	18 benefits and extend or replace health insurance,
372	372	19 life insurance, and other employment benefits;
373	373	20 (iv) all training and skill development
374	374	21 programs to be made available for workers who will
375	375	22 see their employment reduced or eliminated as a
376	376	23 result of the retirement; and
377	377	24 (v) any agreements with local governments
378	378	25 regarding continuing tax or other transfer
379	379	26 payments following the facility's retirement
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390	390	1 intended to minimize the impact on local services.
391	391	2 (H) Describe any anticipated capital expenditures
392	392	3 in excess of $1,000,000 at existing generation
393	393	4 facilities and the reason for such expenditures.
394	394	5 (12) A description of all models and methodologies
395	395	6 used in performing the integrated resource planning
396	396	7 process. The utility shall provide to the Agency, upon
397	397	8 request, reasonable access to any computer models used in
398	398	9 the analysis and workpapers, in electronic form, relied on
399	399	10 in preparation of the report.
400	400	11 (e) As part of all integrated resource plans submitted in
401	401	12 2025, the utility shall identify all programs, grants, loans,
402	402	13 or tax benefits for which the utility is eligible pursuant to
403	403	14 the Inflation Reduction Act of 2022, and state whether the
404	404	15 utility has applied for or otherwise used the program, grant,
405	405	16 loan, or tax benefit. If the utility has not yet applied for or
406	406	17 utilized the benefit, the utility shall state whether it
407	407	18 intends to do so.
408	408	19 (f) Each utility shall submit, as part of its integrated
409	409	20 resource plan, a least cost plan for constructing or procuring
410	410	21 renewable energy resources to meet a minimum percentage of its
411	411	22 load for all retail customers as follows: 25% by June 1, 2026,
412	412	23 increasing by at least 3% each delivery year thereafter to at
413	413	24 least 40% by the 2030 delivery year, and continuing at no less
414	414	25 than 40% for each delivery year thereafter.
415	415	26 (g) Beginning in 2031, each utility shall submit, as part
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426	426	1 of its integrated resource plan, a least cost plan for
427	427	2 supplying 100% of its total projected load through renewable
428	428	3 generation resources in combination with storage resources and
429	429	4 demand-side programs by 2045. This least cost plan shall
430	430	5 provide for the retirement of all coal and gas generation
431	431	6 resources by January 1, 2045.
432	432	7 (h) The Agency may adopt rules establishing additional
433	433	8 requirements as to the form and content of integrated resource
434	434	9 plans, including, but not limited to, specifying forecast
435	435	10 methodologies.
436	436	11 Section 20. Stakeholder process. Prior to the submission
437	437	12 of an integrated resource plan, a municipality, municipal
438	438	13 power agency, or electric cooperative required to submit an
439	439	14 integrated resource plan shall hold at least 2 stakeholders
440	440	15 meetings open to all ratepayers and members of the public.
441	441	16 Notice of the meetings shall be sent to all customers not less
442	442	17 than 30 days prior to the meeting. During the meetings the
443	443	18 utility shall describe its processes for developing the
444	444	19 integrated resource plan and its core assumptions and
445	445	20 constraints, present its proposed preferred portfolio, and
446	446	21 describe any planned retirements, capital expenditures on
447	447	22 existing generation resources likely to exceed $1,000,000, and
448	448	23 planned construction. Each meeting shall allow time for public
449	449	24 comment and the utility shall provide attendees with a means
450	450	25 of providing public comment in writing following the meeting.
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461	461	1 Section 25. Procedures for submission of integrated
462	462	2 resource plan.
463	463	3 (a) Each municipality, municipal power agency, and
464	464	4 electric cooperative shall submit its integrated resource
465	465	5 plan, as set forth in this Act, to the Agency by October 1 of
466	466	6 the calendar year.
467	467	7 (b) The Agency may request further information from the
468	468	8 utility. Any such requests shall be made in writing. If the
469	469	9 Agency requests additional information, the utility shall
470	470	10 provide responses no later than 15 days following the request.
471	471	11 (c) The Agency shall facilitate public comment on the
472	472	12 integrated resource plan, as follows:
473	473	13 (1) upon submission of the integrated resource plan,
474	474	14 the Agency shall post the integrated resource plan
475	475	15 publicly on its website. The plan shall remain publicly
476	476	16 accessible for at least 60 days.
477	477	17 (2) the utility shall hold at least 2 public meetings,
478	478	18 one in person and one remotely, where it shall make a
479	479	19 representative available to address questions about the
480	480	20 resource plan. The meetings shall be held no sooner than
481	481	21 15 days, and no later than 45 days, after the integrated
482	482	22 resource plan is made available to the public.
483	483	23 (3) the Agency shall accept public comments on the
484	484	24 integrated resource plan for 60 days following its public
485	485	25 posting via website, email, or mail. The Agency may extend
486	486
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496	496	1 this public comment period by an additional 60 days upon
497	497	2 request by members of the public; and
498	498	3 (4) after the conclusion of the public comment period,
499	499	4 as determined by the Agency, the Agency shall transmit
500	500	5 copies of all public comments received to the utility.
501	501	6 (d) The utility shall review public comments and provide
502	502	7 responses that reasonably address all issues or questions
503	503	8 raised by such comments. The utility may modify its integrated
504	504	9 resource plan in response to these comments. The utility shall
505	505	10 prepare a document with responses to public comments and
506	506	11 submit this response document to the Agency no later than 90
507	507	12 days after receiving the comments from the agency. This
508	508	13 response document shall be posted publicly on the Agency's
509	509	14 website along with the original integrated resource plan, as
510	510	15 submitted, and any revisions made by the utility in response
511	511	16 to public comments.
512	512	17 (e) The Agency shall maintain public access to all
513	513	18 integrated resource plans submitted pursuant to this Act,
514	514	19 accessible through the Agency's website, for no less than 10
515	515	20 years following each integrated resource plan's initial
516	516	21 submission.
517	517	22 Section 30. Cost of Service Study.
518	518	23 (a) All electric cooperatives with members in this State,
519	519	24 municipal power agencies, and municipalities with $5,000,000
520	520	25 or more in total retail electricity revenues shall submit to
521	521
522	522
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531	531	1 the Agency an embedded cost-of-service study on November 1,
532	532	2 2025 and on November 1 every 3 years thereafter.
533	533	3 (b) The format and contents of such study shall be
534	534	4 consistent with those set forth in any rules or regulations by
535	535	5 the Illinois Commerce Commission for cost-of-service studies
536	536	6 by electric utilities subject to retail rate approval by the
537	537	7 Commerce Commission.
538	538	8 Section 35. Use of independent expert.
539	539	9 (a) The Agency shall maintain a list of qualified experts
540	540	10 or expert consulting firms for the purpose of developing
541	541	11 integrated resource plans on behalf of municipalities,
542	542	12 municipal power agencies, and cooperatives. In order to
543	543	13 qualify an expert or expert consulting firm must have:
544	544	14 (1) direct previous experience assembling power supply
545	545	15 plans or portfolios for utilities;
546	546	16 (2) an advanced degree in economics, mathematics,
547	547	17 engineering, risk management, or a related area of study;
548	548	18 (3) 10 years of experience in the electricity sector;
549	549	19 (4) expertise in wholesale electricity market rules,
550	550	20 including those established by the federal Energy
551	551	21 Regulatory Commission and regional transmission
552	552	22 organizations; and
553	553	23 (5) adequate resources to perform and fulfill the
554	554	24 required functions and responsibilities.
555	555	25 (b) The Agency may assemble the list as part of the process
556	556
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566	566	1 for developing a list of qualified experts for experts to
567	567	2 develop procurement plans, as set forth in subsection (a) of
568	568	3 Section 1-75 of the Illinois Power Agency Act.
569	569	4 (c) The Agency shall provide affected utilities and other
570	570	5 interested parties with the lists of qualified experts or
571	571	6 expert consulting firms identified through the request for
572	572	7 qualifications processes that are under consideration to
573	573	8 prepare the integrated resource plan on behalf of the utility.
574	574	9 The Agency shall also provide each qualified expert's or
575	575	10 expert consulting firm's response to the request for
576	576	11 qualifications. A utility shall, within 5 business days,
577	577	12 notify the Agency in writing if it objects to any experts or
578	578	13 expert consulting firms on the lists. Objections shall be
579	579	14 based on:
580	580	15 (1) the failure to satisfy qualification criteria;
581	581	16 (2) the identification of a conflict of interest; or
582	582	17 (3) the evidence of inappropriate bias for or against
583	583	18 potential bidders or the affected utilities.
584	584	19 The Agency shall remove experts or expert consulting firms
585	585	20 from the lists within 10 days if there is a reasonable basis
586	586	21 for an objection and provide the updated lists to the affected
587	587	22 utilities and other interested parties. If the Agency fails to
588	588	23 remove an expert or expert consulting firm from the list, the
589	589	24 objecting utility may withdraw its application and develop its
590	590	25 integrated resource plan without agency assistance.
591	591	26 (d) A utility required to submit an integrated resource
592	592
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602	602	1 plan may elect to rely on an expert or expert consulting firm
603	603	2 selected by the Agency to develop the plan and conduct
604	604	3 stakeholder processes.
605	605	4 (e) A utility may submit a request to the Agency, not less
606	606	5 than 6 months prior to the date on which the integrated
607	607	6 resource plan is due, for such an expert or expert consulting
608	608	7 firm.
609	609	8 (f) Upon receipt of such a request, the Agency shall issue
610	610	9 requests for proposals to the qualified experts on the list
611	611	10 assembled as set forth in subsections (a) through (c) to
612	612	11 develop an integrated resource plan for that utility. The
613	613	12 Agency shall select an expert or expert consulting firm to
614	614	13 develop the integrated resource plan on behalf of the utility
615	615	14 based on the proposals submitted.
616	616	15 (g) Subject to appropriation, if a utility elects to rely
617	617	16 on an expert or expert consulting firm selected by the Agency,
618	618	17 90% of the costs assessed by the expert for development of the
619	619	18 integrated resource plan shall be paid by the Agency, up to
620	620	19 $250,000, and the remainder paid by the utility.
621	621	20 Section 40. Electric cooperatives member access.
622	622	21 (a) As used in this Section, "meeting" has the meaning
623	623	22 given to that term in Section 1.02 of the Open Meetings Act.
624	624	23 (b) As used in this Section, except for subsection (j),
625	625	24 "member" includes all members of an electric cooperative in
626	626	25 accordance with the cooperative's bylaws. Where a generation
627	627
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637	637	1 and transmission electric cooperative's members are electric
638	638	2 cooperatives rather than individuals, members of those
639	639	3 member-cooperatives are members of the generation and
640	640	4 transmission electric cooperative for purposes of this
641	641	5 Section. As used in subsection (j), "member" includes only
642	642	6 members of an electric cooperative with individual members.
643	643	7 (c) All meetings of an electric cooperative shall be open
644	644	8 to all members, except that a cooperative, by a two-thirds
645	645	9 affirmative vote of the board members present, may go into
646	646	10 executive session for consideration of documents or
647	647	11 information deemed to be confidential for legal, commercial,
648	648	12 or personnel purposes.
649	649	13 (1) Before a board of directors convenes in executive
650	650	14 session, the board shall announce the general topic of the
651	651	15 executive session.
652	652	16 (2) Notice of all meetings of an electric cooperative
653	653	17 shall be posted on the website of the electric cooperative
654	654	18 at least 30 days prior to the meeting, except for any
655	655	19 annual meeting, which shall be posted at least 120 days
656	656	20 prior. Minutes of all meetings of an electric cooperative
657	657	21 shall be posted on the website of the electric cooperative
658	658	22 as soon as they have been approved and shall remain posted
659	659	23 for at least one year after the date of the meeting. Upon
660	660	24 request of a member, the electric cooperative shall make
661	661	25 minutes of any meeting held after the effective date of
662	662	26 this Act available. Minutes shall include the votes of
663	663
664	664
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673	673	1 each member of the board on all items for which approval
674	674	2 was not unanimous.
675	675	3 (3) At every regular meeting of the governing body of
676	676	4 an electric cooperative, members of the cooperative shall
677	677	5 be given an opportunity to address the board on any matter
678	678	6 concerning the policies and businesses of the cooperative.
679	679	7 The board may place reasonable, viewpoint-neutral
680	680	8 restrictions on the amount and duration of member comment.
681	681	9 (d) Each electric cooperative shall post on its website
682	682	10 its current rates. The electric cooperative shall keep and
683	683	11 make available to any member, upon request, all financial
684	684	12 audits of the electric cooperative conducted in the last 3
685	685	13 fiscal years.
686	686	14 (e) Each electric cooperative shall adopt and post a
687	687	15 written policy governing the election of directors on its
688	688	16 website. The electric cooperative shall provide notice of the
689	689	17 policy at the time a person becomes a member, as a bill insert
690	690	18 at least once per year, and on request. The policy shall
691	691	19 contain true and complete information on the following:
692	692	20 (1) Who is entitled to vote in an election, including
693	693	21 how member cooperatives may vote.
694	694	22 (2) How a member may obtain and cast a ballot.
695	695	23 (3) The postmark deadline for any ballots submitted by
696	696	24 mail.
697	697	25 (4) How a member may become a candidate for the board
698	698	26 or any other elected leadership positions.
699	699
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709	709	1 (f) Electric cooperatives shall enable their members to
710	710	2 vote in any election for one or more directors by mail-in
711	711	3 ballot, as follows:
712	712	4 (1) The electric cooperative shall affirmatively mail
713	713	5 each of its members a ballot no later than 30 days before
714	714	6 ballots are due. Ballots may be mailed separately and
715	715	7 clearly marked as such or included as a bill insert.
716	716	8 (2) The electric cooperative shall accept ballots by
717	717	9 mail if postmarked by the date indicated in the
718	718	10 cooperative's written policy.
719	719	11 (3) The electric cooperative may allow for in-person
720	720	12 voting in addition to mail.
721	721	13 (g) Electric cooperatives may establish a system for
722	722	14 online voting in addition to a mail-in option.
723	723	15 (h) At least 120 days before each board election, the
724	724	16 electric cooperative shall post a list of candidates and
725	725	17 deadline to return ballots on its website and leave the
726	726	18 information posted until the election has concluded. The same
727	727	19 information shall be included as part of a bill insert for a
728	728	20 billing cycle occurring at no more than 120 but no fewer than
729	729	21 15 days prior to the deadline to return ballots.
730	730	22 (i) Each candidate for a position on the board of
731	731	23 directors who has qualified under the electric cooperative's
732	732	24 bylaws is entitled to receive a membership list in electronic
733	733	25 format upon receipt and verification of any candidacy
734	734	26 requirements. Such a list shall be provided to a candidate no
735	735
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745	745	1 later than 15 days after requested by the candidate. The
746	746	2 membership list must include the names, phone numbers, and
747	747	3 addresses of all members as they appear in the electric
748	748	4 cooperative's records.
749	749	5 Section 45. Conflict of interest.
750	750	6 (a) Each electric cooperative, municipality, and municipal
751	751	7 power agency shall adopt, and post publicly on its website,
752	752	8 written policies concerning:
753	753	9 (1) The compensation provided to a director on the
754	754	10 board of directors, including information on any
755	755	11 authorized per diem amounts, and the values of other
756	756	12 benefits, services, or goods that a director receives.
757	757	13 (2) The disclosure of any gifts received by a director
758	758	14 in excess of a de minimis amount.
759	759	15 (3) The requirements and procedures for a director on
760	760	16 the board of directors to disclose in writing any
761	761	17 conflicts of interest. At a minimum, the policy must
762	762	18 require disclosure when a decision before the board could
763	763	19 provide directly and as a proximate result of the decision
764	764	20 a financial or other material benefit to:
765	765	21 (A) The director, if the benefit is unique to that
766	766	22 director and not shared by similarly situated
767	767	23 cooperative members.
768	768	24 (B) A parent, grandparent, spouse, partner in a
769	769	25 civil union, child, or sibling of the director, if the
770	770
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780	780	1 benefit is unique to that director and not shared by
781	781	2 similarly situated cooperative members.
782	782	3 (C) An entity in which the director is an officer
783	783	4 or director or has a financial interest not shared by
784	784	5 similarly situated cooperative members.
785	785	6 (b) Each electric cooperative shall disclose on its
786	786	7 website all lobbying activities as defined by Section 2 of the
787	787	8 Lobbyist Registration Act and the amount of expenditures on
788	788	9 such activities on an annual basis. Where the electric
789	789	10 cooperative is a member of a trade association or other
790	790	11 organization that engages in lobbying activities, the electric
791	791	12 cooperative shall post the amount of dues or other
792	792	13 expenditures paid by the cooperative to such an organization
793	793	14 and what percentage of the organization or association's
794	794	15 budget is spent on lobbying activities.
795	795	16 (c) Notwithstanding any other law to the contrary, if an
796	796	17 individual is a director on the board of directors of both a
797	797	18 distribution cooperative electric association and a generation
798	798	19 and transmission cooperative association, the director owes
799	799	20 fiduciary duties to both associations and shall not be
800	800	21 required to give priority to a fiduciary duty the director
801	801	22 owes to one association over the duties the director owes to
802	802	23 the other association.
803	803	24 Section 90. The Open Meetings Act is amended by changing
804	804	25 Section 2 as follows:
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815	815	1 (5 ILCS 120/2) (from Ch. 102, par. 42)
816	816	2 Sec. 2. Open meetings.
817	817	3 (a) Openness required. All meetings of public bodies shall
818	818	4 be open to the public unless excepted in subsection (c) and
819	819	5 closed in accordance with Section 2a.
820	820	6 (b) Construction of exceptions. The exceptions contained
821	821	7 in subsection (c) are in derogation of the requirement that
822	822	8 public bodies meet in the open, and therefore, the exceptions
823	823	9 are to be strictly construed, extending only to subjects
824	824	10 clearly within their scope. The exceptions authorize but do
825	825	11 not require the holding of a closed meeting to discuss a
826	826	12 subject included within an enumerated exception.
827	827	13 (c) Exceptions. A public body may hold closed meetings to
828	828	14 consider the following subjects:
829	829	15 (1) The appointment, employment, compensation,
830	830	16 discipline, performance, or dismissal of specific
831	831	17 employees, specific individuals who serve as independent
832	832	18 contractors in a park, recreational, or educational
833	833	19 setting, or specific volunteers of the public body or
834	834	20 legal counsel for the public body, including hearing
835	835	21 testimony on a complaint lodged against an employee, a
836	836	22 specific individual who serves as an independent
837	837	23 contractor in a park, recreational, or educational
838	838	24 setting, or a volunteer of the public body or against
839	839	25 legal counsel for the public body to determine its
840	840
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842	842
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850	850	1 validity. However, a meeting to consider an increase in
851	851	2 compensation to a specific employee of a public body that
852	852	3 is subject to the Local Government Wage Increase
853	853	4 Transparency Act may not be closed and shall be open to the
854	854	5 public and posted and held in accordance with this Act.
855	855	6 (2) Collective negotiating matters between the public
856	856	7 body and its employees or their representatives, or
857	857	8 deliberations concerning salary schedules for one or more
858	858	9 classes of employees.
859	859	10 (3) The selection of a person to fill a public office,
860	860	11 as defined in this Act, including a vacancy in a public
861	861	12 office, when the public body is given power to appoint
862	862	13 under law or ordinance, or the discipline, performance or
863	863	14 removal of the occupant of a public office, when the
864	864	15 public body is given power to remove the occupant under
865	865	16 law or ordinance.
866	866	17 (4) Evidence or testimony presented in open hearing,
867	867	18 or in closed hearing where specifically authorized by law,
868	868	19 to a quasi-adjudicative body, as defined in this Act,
869	869	20 provided that the body prepares and makes available for
870	870	21 public inspection a written decision setting forth its
871	871	22 determinative reasoning.
872	872	23 (4.5) Evidence or testimony presented to a school
873	873	24 board regarding denial of admission to school events or
874	874	25 property pursuant to Section 24-24 of the School Code,
875	875	26 provided that the school board prepares and makes
876	876
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886	886	1 available for public inspection a written decision setting
887	887	2 forth its determinative reasoning.
888	888	3 (5) The purchase or lease of real property for the use
889	889	4 of the public body, including meetings held for the
890	890	5 purpose of discussing whether a particular parcel should
891	891	6 be acquired.
892	892	7 (6) The setting of a price for sale or lease of
893	893	8 property owned by the public body.
894	894	9 (7) The sale or purchase of securities, investments,
895	895	10 or investment contracts. This exception shall not apply to
896	896	11 the investment of assets or income of funds deposited into
897	897	12 the Illinois Prepaid Tuition Trust Fund.
898	898	13 (8) Security procedures, school building safety and
899	899	14 security, and the use of personnel and equipment to
900	900	15 respond to an actual, a threatened, or a reasonably
901	901	16 potential danger to the safety of employees, students,
902	902	17 staff, the public, or public property.
903	903	18 (9) Student disciplinary cases.
904	904	19 (10) The placement of individual students in special
905	905	20 education programs and other matters relating to
906	906	21 individual students.
907	907	22 (11) Litigation, when an action against, affecting or
908	908	23 on behalf of the particular public body has been filed and
909	909	24 is pending before a court or administrative tribunal, or
910	910	25 when the public body finds that an action is probable or
911	911	26 imminent, in which case the basis for the finding shall be
912	912
913	913
914	914
915	915
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922	922	1 recorded and entered into the minutes of the closed
923	923	2 meeting.
924	924	3 (12) The establishment of reserves or settlement of
925	925	4 claims as provided in the Local Governmental and
926	926	5 Governmental Employees Tort Immunity Act, if otherwise the
927	927	6 disposition of a claim or potential claim might be
928	928	7 prejudiced, or the review or discussion of claims, loss or
929	929	8 risk management information, records, data, advice or
930	930	9 communications from or with respect to any insurer of the
931	931	10 public body or any intergovernmental risk management
932	932	11 association or self insurance pool of which the public
933	933	12 body is a member.
934	934	13 (13) Conciliation of complaints of discrimination in
935	935	14 the sale or rental of housing, when closed meetings are
936	936	15 authorized by the law or ordinance prescribing fair
937	937	16 housing practices and creating a commission or
938	938	17 administrative agency for their enforcement.
939	939	18 (14) Informant sources, the hiring or assignment of
940	940	19 undercover personnel or equipment, or ongoing, prior or
941	941	20 future criminal investigations, when discussed by a public
942	942	21 body with criminal investigatory responsibilities.
943	943	22 (15) Professional ethics or performance when
944	944	23 considered by an advisory body appointed to advise a
945	945	24 licensing or regulatory agency on matters germane to the
946	946	25 advisory body's field of competence.
947	947	26 (16) Self evaluation, practices and procedures or
948	948
949	949
950	950
951	951
952	952
953	953	HB3779 - 26 - LRB104 11172 AAS 21254 b
954	954
955	955
956	956	HB3779- 27 -LRB104 11172 AAS 21254 b HB3779 - 27 - LRB104 11172 AAS 21254 b
957	957	HB3779 - 27 - LRB104 11172 AAS 21254 b
958	958	1 professional ethics, when meeting with a representative of
959	959	2 a statewide association of which the public body is a
960	960	3 member.
961	961	4 (17) The recruitment, credentialing, discipline or
962	962	5 formal peer review of physicians or other health care
963	963	6 professionals, or for the discussion of matters protected
964	964	7 under the federal Patient Safety and Quality Improvement
965	965	8 Act of 2005, and the regulations promulgated thereunder,
966	966	9 including 42 C.F.R. Part 3 (73 FR 70732), or the federal
967	967	10 Health Insurance Portability and Accountability Act of
968	968	11 1996, and the regulations promulgated thereunder,
969	969	12 including 45 C.F.R. Parts 160, 162, and 164, by a
970	970	13 hospital, or other institution providing medical care,
971	971	14 that is operated by the public body.
972	972	15 (18) Deliberations for decisions of the Prisoner
973	973	16 Review Board.
974	974	17 (19) Review or discussion of applications received
975	975	18 under the Experimental Organ Transplantation Procedures
976	976	19 Act.
977	977	20 (20) The classification and discussion of matters
978	978	21 classified as confidential or continued confidential by
979	979	22 the State Government Suggestion Award Board.
980	980	23 (21) Discussion of minutes of meetings lawfully closed
981	981	24 under this Act, whether for purposes of approval by the
982	982	25 body of the minutes or semi-annual review of the minutes
983	983	26 as mandated by Section 2.06.
984	984
985	985
986	986
987	987
988	988
989	989	HB3779 - 27 - LRB104 11172 AAS 21254 b
990	990
991	991
992	992	HB3779- 28 -LRB104 11172 AAS 21254 b HB3779 - 28 - LRB104 11172 AAS 21254 b
993	993	HB3779 - 28 - LRB104 11172 AAS 21254 b
994	994	1 (22) Deliberations for decisions of the State
995	995	2 Emergency Medical Services Disciplinary Review Board.
996	996	3 (23) The operation by a municipality of a municipal
997	997	4 utility or the operation of a municipal power agency or
998	998	5 municipal natural gas agency when the discussion involves
999	999	6 (i) trade secrets, (ii) ongoing contract negotiations or
1000	1000	7 results of a request for proposals relating to the
1001	1001	8 purchase, sale, or delivery of electricity or natural gas
1002	1002	9 from nonaffiliate entities, or (iii) information
1003	1003	10 prohibited from disclosure by a regional transmission
1004	1004	11 organization to ensure the integrity of competitive
1005	1005	12 markets contracts relating to the purchase, sale, or
1006	1006	13 delivery of electricity or natural gas or (ii) the results
1007	1007	14 or conclusions of load forecast studies.
1008	1008	15 (24) Meetings of a residential health care facility
1009	1009	16 resident sexual assault and death review team or the
1010	1010	17 Executive Council under the Abuse Prevention Review Team
1011	1011	18 Act.
1012	1012	19 (25) Meetings of an independent team of experts under
1013	1013	20 Brian's Law.
1014	1014	21 (26) Meetings of a mortality review team appointed
1015	1015	22 under the Department of Juvenile Justice Mortality Review
1016	1016	23 Team Act.
1017	1017	24 (27) (Blank).
1018	1018	25 (28) Correspondence and records (i) that may not be
1019	1019	26 disclosed under Section 11-9 of the Illinois Public Aid
1020	1020
1021	1021
1022	1022
1023	1023
1024	1024
1025	1025	HB3779 - 28 - LRB104 11172 AAS 21254 b
1026	1026
1027	1027
1028	1028	HB3779- 29 -LRB104 11172 AAS 21254 b HB3779 - 29 - LRB104 11172 AAS 21254 b
1029	1029	HB3779 - 29 - LRB104 11172 AAS 21254 b
1030	1030	1 Code or (ii) that pertain to appeals under Section 11-8 of
1031	1031	2 the Illinois Public Aid Code.
1032	1032	3 (29) Meetings between internal or external auditors
1033	1033	4 and governmental audit committees, finance committees, and
1034	1034	5 their equivalents, when the discussion involves internal
1035	1035	6 control weaknesses, identification of potential fraud risk
1036	1036	7 areas, known or suspected frauds, and fraud interviews
1037	1037	8 conducted in accordance with generally accepted auditing
1038	1038	9 standards of the United States of America.
1039	1039	10 (30) (Blank).
1040	1040	11 (31) Meetings and deliberations for decisions of the
1041	1041	12 Concealed Carry Licensing Review Board under the Firearm
1042	1042	13 Concealed Carry Act.
1043	1043	14 (32) Meetings between the Regional Transportation
1044	1044	15 Authority Board and its Service Boards when the discussion
1045	1045	16 involves review by the Regional Transportation Authority
1046	1046	17 Board of employment contracts under Section 28d of the
1047	1047	18 Metropolitan Transit Authority Act and Sections 3A.18 and
1048	1048	19 3B.26 of the Regional Transportation Authority Act.
1049	1049	20 (33) Those meetings or portions of meetings of the
1050	1050	21 advisory committee and peer review subcommittee created
1051	1051	22 under Section 320 of the Illinois Controlled Substances
1052	1052	23 Act during which specific controlled substance prescriber,
1053	1053	24 dispenser, or patient information is discussed.
1054	1054	25 (34) Meetings of the Tax Increment Financing Reform
1055	1055	26 Task Force under Section 2505-800 of the Department of
1056	1056
1057	1057
1058	1058
1059	1059
1060	1060
1061	1061	HB3779 - 29 - LRB104 11172 AAS 21254 b
1062	1062
1063	1063
1064	1064	HB3779- 30 -LRB104 11172 AAS 21254 b HB3779 - 30 - LRB104 11172 AAS 21254 b
1065	1065	HB3779 - 30 - LRB104 11172 AAS 21254 b
1066	1066	1 Revenue Law of the Civil Administrative Code of Illinois.
1067	1067	2 (35) Meetings of the group established to discuss
1068	1068	3 Medicaid capitation rates under Section 5-30.8 of the
1069	1069	4 Illinois Public Aid Code.
1070	1070	5 (36) Those deliberations or portions of deliberations
1071	1071	6 for decisions of the Illinois Gaming Board in which there
1072	1072	7 is discussed any of the following: (i) personal,
1073	1073	8 commercial, financial, or other information obtained from
1074	1074	9 any source that is privileged, proprietary, confidential,
1075	1075	10 or a trade secret; or (ii) information specifically
1076	1076	11 exempted from the disclosure by federal or State law.
1077	1077	12 (37) Deliberations for decisions of the Illinois Law
1078	1078	13 Enforcement Training Standards Board, the Certification
1079	1079	14 Review Panel, and the Illinois State Police Merit Board
1080	1080	15 regarding certification and decertification.
1081	1081	16 (38) Meetings of the Ad Hoc Statewide Domestic
1082	1082	17 Violence Fatality Review Committee of the Illinois
1083	1083	18 Criminal Justice Information Authority Board that occur in
1084	1084	19 closed executive session under subsection (d) of Section
1085	1085	20 35 of the Domestic Violence Fatality Review Act.
1086	1086	21 (39) Meetings of the regional review teams under
1087	1087	22 subsection (a) of Section 75 of the Domestic Violence
1088	1088	23 Fatality Review Act.
1089	1089	24 (40) Meetings of the Firearm Owner's Identification
1090	1090	25 Card Review Board under Section 10 of the Firearm Owners
1091	1091	26 Identification Card Act.
1092	1092
1093	1093
1094	1094
1095	1095
1096	1096
1097	1097	HB3779 - 30 - LRB104 11172 AAS 21254 b
1098	1098
1099	1099
1100	1100	HB3779- 31 -LRB104 11172 AAS 21254 b HB3779 - 31 - LRB104 11172 AAS 21254 b
1101	1101	HB3779 - 31 - LRB104 11172 AAS 21254 b
1102	1102	1 (d) Definitions. For purposes of this Section:
1103	1103	2 "Employee" means a person employed by a public body whose
1104	1104	3 relationship with the public body constitutes an
1105	1105	4 employer-employee relationship under the usual common law
1106	1106	5 rules, and who is not an independent contractor.
1107	1107	6 "Public office" means a position created by or under the
1108	1108	7 Constitution or laws of this State, the occupant of which is
1109	1109	8 charged with the exercise of some portion of the sovereign
1110	1110	9 power of this State. The term "public office" shall include
1111	1111	10 members of the public body, but it shall not include
1112	1112	11 organizational positions filled by members thereof, whether
1113	1113	12 established by law or by a public body itself, that exist to
1114	1114	13 assist the body in the conduct of its business.
1115	1115	14 "Quasi-adjudicative body" means an administrative body
1116	1116	15 charged by law or ordinance with the responsibility to conduct
1117	1117	16 hearings, receive evidence or testimony and make
1118	1118	17 determinations based thereon, but does not include local
1119	1119	18 electoral boards when such bodies are considering petition
1120	1120	19 challenges.
1121	1121	20 (e) Final action. No final action may be taken at a closed
1122	1122	21 meeting. Final action shall be preceded by a public recital of
1123	1123	22 the nature of the matter being considered and other
1124	1124	23 information that will inform the public of the business being
1125	1125	24 conducted.
1126	1126	25 (Source: P.A. 102-237, eff. 1-1-22; 102-520, eff. 8-20-21;
1127	1127	26 102-558, eff. 8-20-21; 102-813, eff. 5-13-22; 103-311, eff.
1128	1128
1129	1129
1130	1130
1131	1131
1132	1132
1133	1133	HB3779 - 31 - LRB104 11172 AAS 21254 b
1134	1134
1135	1135
1136	1136	HB3779- 32 -LRB104 11172 AAS 21254 b HB3779 - 32 - LRB104 11172 AAS 21254 b
1137	1137	HB3779 - 32 - LRB104 11172 AAS 21254 b
1138	1138	1 7-28-23; 103-626, eff. 1-1-25.)
1139	1139	2 Section 95. The Department of Commerce and Economic
1140	1140	3 Opportunity Law of the Civil Administrative Code of Illinois
1141	1141	4 is amended by changing Section 605-1075 as follows:
1142	1142	5 (20 ILCS 605/605-1075)
1143	1143	6 Sec. 605-1075. Energy Transition Assistance Fund.
1144	1144	7 (a) The General Assembly hereby declares that management
1145	1145	8 of several economic development programs requires a
1146	1146	9 consolidated funding source to improve resource efficiency.
1147	1147	10 The General Assembly specifically recognizes that properly
1148	1148	11 serving communities and workers impacted by the energy
1149	1149	12 transition requires that the Department of Commerce and
1150	1150	13 Economic Opportunity have access to the resources required for
1151	1151	14 the execution of the programs for workforce and contractor
1152	1152	15 development, just transition investments and community
1153	1153	16 support, and the implementation and administration of energy
1154	1154	17 and justice efforts by the State.
1155	1155	18 (b) The Department shall be responsible for the
1156	1156	19 administration of the Energy Transition Assistance Fund and
1157	1157	20 shall allocate funding on the basis of priorities established
1158	1158	21 in this Section. Each year, the Department shall determine the
1159	1159	22 available amount of resources in the Fund that can be
1160	1160	23 allocated to the programs identified in this Section, and
1161	1161	24 allocate the funding accordingly. The Department shall, to the
1162	1162
1163	1163
1164	1164
1165	1165
1166	1166
1167	1167	HB3779 - 32 - LRB104 11172 AAS 21254 b
1168	1168
1169	1169
1170	1170	HB3779- 33 -LRB104 11172 AAS 21254 b HB3779 - 33 - LRB104 11172 AAS 21254 b
1171	1171	HB3779 - 33 - LRB104 11172 AAS 21254 b
1172	1172	1 extent practical, consider both the short-term and long-term
1173	1173	2 costs of the programs and allocate funding so that the
1174	1174	3 Department is able to cover both the short-term and long-term
1175	1175	4 costs of these programs using projected revenue.
1176	1176	5 The available funding for each year shall be allocated
1177	1177	6 from the Fund in the following order of priority:
1178	1178	7 (1) for costs related to the Clean Jobs Workforce
1179	1179	8 Network Program, up to $21,000,000 annually prior to June
1180	1180	9 1, 2023; and $24,333,333 annually from June 1, 2023 to May
1181	1181	10 30, 2025; and $26,020,736 annually thereafter;
1182	1182	11 (2) for costs related to the Clean Energy Contractor
1183	1183	12 Incubator Program, up to $21,000,000 annually prior to
1184	1184	13 June 1, 2025 and $22,687,403 thereafter;
1185	1185	14 (3) for costs related to the Clean Energy Primes
1186	1186	15 Contractor Accelerator Program, up to $9,000,000 annually;
1187	1187	16 (4) for costs related to the Barrier Reduction
1188	1188	17 Program, up to $21,000,000 annually prior to June 1, 2025
1189	1189	18 and $22,143,079 annually thereafter;
1190	1190	19 (5) for costs related to the Jobs and Environmental
1191	1191	20 Justice Grant Program, up to $34,000,000 annually;
1192	1192	21 (6) for costs related to the Returning Residents Clean
1193	1193	22 Jobs Training Program, up to $6,000,000 annually;
1194	1194	23 (7) for costs related to Energy Transition Navigators,
1195	1195	24 up to $6,000,000 annually prior to June 1, 2025 and
1196	1196	25 $6,482,115 annually thereafter;
1197	1197	26 (8) for costs related to the Illinois Climate Works
1198	1198
1199	1199
1200	1200
1201	1201
1202	1202
1203	1203	HB3779 - 33 - LRB104 11172 AAS 21254 b
1204	1204
1205	1205
1206	1206	HB3779- 34 -LRB104 11172 AAS 21254 b HB3779 - 34 - LRB104 11172 AAS 21254 b
1207	1207	HB3779 - 34 - LRB104 11172 AAS 21254 b
1208	1208	1 Preapprenticeship Program, up to $10,000,000 annually;
1209	1209	2 (9) for costs related to Energy Transition Community
1210	1210	3 Support Grants, up to $40,000,000 annually;
1211	1211	4 (10) for costs related to the Displaced Energy Worker
1212	1212	5 Dependent Scholarship, upon request by the Illinois
1213	1213	6 Student Assistance Commission, up to $1,100,000 annually;
1214	1214	7 (11) up to $10,000,000 annually shall be transferred
1215	1215	8 to the Public Utilities Fund for use by the Illinois
1216	1216	9 Commerce Commission for costs of administering the changes
1217	1217	10 made to the Public Utilities Act by this amendatory Act of
1218	1218	11 the 102nd General Assembly;
1219	1219	12 (12) up to $4,000,000 annually shall be transferred to
1220	1220	13 the Illinois Power Agency Operations Fund for use by the
1221	1221	14 Illinois Power Agency; and
1222	1222	15 (13) for costs related to the Clean Energy Jobs and
1223	1223	16 Justice Fund, up to $1,000,000 annually.
1224	1224	17 The Department is authorized to utilize up to 10% of the
1225	1225	18 Energy Transition Assistance Fund for administrative and
1226	1226	19 operational expenses to implement the requirements of this
1227	1227	20 Act.
1228	1228	21 (c) Within 30 days after the effective date of this
1229	1229	22 amendatory Act of the 102nd General Assembly, each electric
1230	1230	23 utility serving more than 500,000 customers in the State shall
1231	1231	24 report to the Department its total kilowatt-hours of energy
1232	1232	25 delivered during the 12 months ending on the immediately
1233	1233	26 preceding May 31. By October 31, 2021 and each October 31
1234	1234
1235	1235
1236	1236
1237	1237
1238	1238
1239	1239	HB3779 - 34 - LRB104 11172 AAS 21254 b
1240	1240
1241	1241
1242	1242	HB3779- 35 -LRB104 11172 AAS 21254 b HB3779 - 35 - LRB104 11172 AAS 21254 b
1243	1243	HB3779 - 35 - LRB104 11172 AAS 21254 b
1244	1244	1 thereafter, each electric utility serving more than 500,000
1245	1245	2 customers in the State shall report to the Department its
1246	1246	3 total kilowatt-hours of energy delivered during the 12 months
1247	1247	4 ending on the immediately preceding May 31.
1248	1248	5 (d) The Department shall, within 60 days after the
1249	1249	6 effective date of this amendatory Act of the 102nd General
1250	1250	7 Assembly:
1251	1251	8 (1) determine the amount necessary, but not more than
1252	1252	9 $180,000,000, to meet the funding needs of the programs
1253	1253	10 reliant upon the Energy Transition Assistance Fund as a
1254	1254	11 revenue source for the period between the effective date
1255	1255	12 of this amendatory Act of the 102nd General Assembly and
1256	1256	13 December 31, 2021;
1257	1257	14 (2) determine, based on the kilowatt-hour deliveries
1258	1258	15 for the 12 months ending May 31, 2021 reported by the
1259	1259	16 electric utilities under subsection (c), the total energy
1260	1260	17 transition assistance charge to be allocated to each
1261	1261	18 electric utility for the period between the effective date
1262	1262	19 of this amendatory Act of the 102nd General Assembly and
1263	1263	20 December 31, 2021; and
1264	1264	21 (3) report the total energy transition assistance
1265	1265	22 charge applicable until December 31, 2021 to each electric
1266	1266	23 utility serving more than 500,000 customers in the State
1267	1267	24 and the Illinois Commerce Commission for purposes of
1268	1268	25 filing the tariff pursuant to Section 16-108.30 of the
1269	1269	26 Public Utilities Act.
1270	1270
1271	1271
1272	1272
1273	1273
1274	1274
1275	1275	HB3779 - 35 - LRB104 11172 AAS 21254 b
1276	1276
1277	1277
1278	1278	HB3779- 36 -LRB104 11172 AAS 21254 b HB3779 - 36 - LRB104 11172 AAS 21254 b
1279	1279	HB3779 - 36 - LRB104 11172 AAS 21254 b
1280	1280	1 (e) The Department shall by November 30, 2021, and each
1281	1281	2 November 30 thereafter:
1282	1282	3 (1) determine the amount necessary, but not more than
1283	1283	4 $185,000,000 $180,000,000, to meet the funding needs of
1284	1284	5 the programs reliant upon the Energy Transition Assistance
1285	1285	6 Fund as a revenue source for the immediately following
1286	1286	7 calendar year;
1287	1287	8 (2) determine, based on the kilowatt-hour deliveries
1288	1288	9 for the 12 months ending on the immediately preceding May
1289	1289	10 31 reported to it by the electric utilities under
1290	1290	11 subsection (c), the total energy transition assistance
1291	1291	12 charge to be allocated to each electric utility for the
1292	1292	13 immediately following calendar year; and
1293	1293	14 (3) report the energy transition assistance charge
1294	1294	15 applicable for the immediately following calendar year to
1295	1295	16 each electric utility serving more than 500,000 customers
1296	1296	17 in the State and the Illinois Commerce Commission for
1297	1297	18 purposes of filing the tariff pursuant to Section
1298	1298	19 16-108.30 of the Public Utilities Act.
1299	1299	20 (f) The energy transition assistance charge may not exceed
1300	1300	21 $185,000,000 $180,000,000 annually. If, at the end of the
1301	1301	22 calendar year, any surplus remains in the Energy Transition
1302	1302	23 Assistance Fund, the Department may allocate the surplus from
1303	1303	24 the fund in the following order of priority:
1304	1304	25 (1) for costs related to the development of the
1305	1305	26 Stretch Energy Codes and other standards at the Capital
1306	1306
1307	1307
1308	1308
1309	1309
1310	1310
1311	1311	HB3779 - 36 - LRB104 11172 AAS 21254 b
1312	1312
1313	1313
1314	1314	HB3779- 37 -LRB104 11172 AAS 21254 b HB3779 - 37 - LRB104 11172 AAS 21254 b
1315	1315	HB3779 - 37 - LRB104 11172 AAS 21254 b
1316	1316	1 Development Board, up to $500,000 annually, at the request
1317	1317	2 of the Board;
1318	1318	3 (2) up to $7,000,000 annually shall be transferred to
1319	1319	4 the Energy Efficiency Trust Fund and Clean Air Act Permit
1320	1320	5 Fund for use by the Environmental Protection Agency for
1321	1321	6 costs related to energy efficiency and weatherization, and
1322	1322	7 costs of implementation, administration, and enforcement
1323	1323	8 of the Clean Air Act; and
1324	1324	9 (3) for costs related to State fleet electrification
1325	1325	10 at the Department of Central Management Services, up to
1326	1326	11 $10,000,000 annually, at the request of the Department.
1327	1327	12 (Source: P.A. 102-662, eff. 9-15-21.)
1328	1328	13 Section 100. The Illinois Power Agency Act is amended by
1329	1329	14 changing Sections 1-5, 1-10, 1-20, 1-56 and 1-75 and by adding
1330	1330	15 Sections 1-79 and 1-93 as follows:
1331	1331	16 (20 ILCS 3855/1-5)
1332	1332	17 Sec. 1-5. Legislative declarations and findings. The
1333	1333	18 General Assembly finds and declares:
1334	1334	19 (1) The health, welfare, and prosperity of all
1335	1335	20 Illinois residents require the provision of adequate,
1336	1336	21 reliable, affordable, efficient, and environmentally
1337	1337	22 sustainable electric service at the lowest total cost over
1338	1338	23 time, taking into account any benefits of price stability.
1339	1339	24 (1.5) To provide the highest quality of life for the
1340	1340
1341	1341
1342	1342
1343	1343
1344	1344
1345	1345	HB3779 - 37 - LRB104 11172 AAS 21254 b
1346	1346
1347	1347
1348	1348	HB3779- 38 -LRB104 11172 AAS 21254 b HB3779 - 38 - LRB104 11172 AAS 21254 b
1349	1349	HB3779 - 38 - LRB104 11172 AAS 21254 b
1350	1350	1 residents of Illinois and to provide for a clean and
1351	1351	2 healthy environment, it is the policy of this State to
1352	1352	3 rapidly transition to 100% clean energy by 2050.
1353	1353	4 (2) (Blank).
1354	1354	5 (3) (Blank).
1355	1355	6 (4) It is necessary to improve the process of
1356	1356	7 procuring electricity to serve Illinois residents, to
1357	1357	8 promote investment in energy efficiency and
1358	1358	9 demand-response measures, and to maintain and support
1359	1359	10 development of clean coal technologies, generation
1360	1360	11 resources that operate at all hours of the day and under
1361	1361	12 all weather conditions, zero emission facilities, and
1362	1362	13 renewable resources.
1363	1363	14 (5) Procuring a diverse electricity supply portfolio
1364	1364	15 will ensure the lowest total cost over time for adequate,
1365	1365	16 reliable, efficient, and environmentally sustainable
1366	1366	17 electric service.
1367	1367	18 (6) Including renewable resources and zero emission
1368	1368	19 credits from zero emission facilities in that portfolio
1369	1369	20 will reduce long-term direct and indirect costs to
1370	1370	21 consumers by decreasing environmental impacts and by
1371	1371	22 avoiding or delaying the need for new generation,
1372	1372	23 transmission, and distribution infrastructure. Developing
1373	1373	24 new renewable energy resources in Illinois, including
1374	1374	25 brownfield solar projects and community solar projects,
1375	1375	26 will help to diversify Illinois electricity supply, avoid
1376	1376
1377	1377
1378	1378
1379	1379
1380	1380
1381	1381	HB3779 - 38 - LRB104 11172 AAS 21254 b
1382	1382
1383	1383
1384	1384	HB3779- 39 -LRB104 11172 AAS 21254 b HB3779 - 39 - LRB104 11172 AAS 21254 b
1385	1385	HB3779 - 39 - LRB104 11172 AAS 21254 b
1386	1386	1 and reduce pollution, reduce peak demand, and enhance
1387	1387	2 public health and well-being of Illinois residents.
1388	1388	3 (7) Developing community solar projects in Illinois
1389	1389	4 will help to expand access to renewable energy resources
1390	1390	5 to more Illinois residents.
1391	1391	6 (8) Developing brownfield solar projects in Illinois
1392	1392	7 will help return blighted or contaminated land to
1393	1393	8 productive use while enhancing public health and the
1394	1394	9 well-being of Illinois residents, including those in
1395	1395	10 environmental justice communities.
1396	1396	11 (9) Energy efficiency, demand-response measures, zero
1397	1397	12 emission energy, and renewable energy are resources
1398	1398	13 currently underused in Illinois. These resources should be
1399	1399	14 used, when cost effective, to reduce costs to consumers,
1400	1400	15 improve reliability, and improve environmental quality and
1401	1401	16 public health.
1402	1402	17 (10) The State should encourage the use of advanced
1403	1403	18 clean coal technologies that capture and sequester carbon
1404	1404	19 dioxide emissions to advance environmental protection
1405	1405	20 goals and to demonstrate the viability of coal and
1406	1406	21 coal-derived fuels in a carbon-constrained economy.
1407	1407	22 (10.5) The State should encourage the development of
1408	1408	23 interregional high voltage direct current (HVDC)
1409	1409	24 transmission lines that benefit Illinois. All ratepayers
1410	1410	25 in the State served by the regional transmission
1411	1411	26 organization where the HVDC converter station is
1412	1412
1413	1413
1414	1414
1415	1415
1416	1416
1417	1417	HB3779 - 39 - LRB104 11172 AAS 21254 b
1418	1418
1419	1419
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1421	1421	HB3779 - 40 - LRB104 11172 AAS 21254 b
1422	1422	1 interconnected benefit from the long-term price stability
1423	1423	2 and market access provided by interregional HVDC
1424	1424	3 transmission facilities. The benefits to Illinois include:
1425	1425	4 reduction in wholesale power prices; access to lower-cost
1426	1426	5 markets; enabling the integration of additional renewable
1427	1427	6 generating units within the State through near
1428	1428	7 instantaneous dispatchability and the provision of
1429	1429	8 ancillary services; creating good-paying union jobs in
1430	1430	9 Illinois; and, enhancing grid reliability and climate
1431	1431	10 resilience via HVDC facilities that are installed
1432	1432	11 underground.
1433	1433	12 (10.6) The health, welfare, and safety of the people
1434	1434	13 of the State are advanced by developing new HVDC
1435	1435	14 transmission lines predominantly along transportation
1436	1436	15 rights-of-way, with an HVDC converter station that is
1437	1437	16 located in the service territory of a public utility as
1438	1438	17 defined in Section 3-105 of the Public Utilities Act
1439	1439	18 serving more than 3,000,000 retail customers, and with a
1440	1440	19 project labor agreement as defined in Section 1-10 of this
1441	1441	20 Act.
1442	1442	21 (11) The General Assembly enacted Public Act 96-0795
1443	1443	22 to reform the State's purchasing processes, recognizing
1444	1444	23 that government procurement is susceptible to abuse if
1445	1445	24 structural and procedural safeguards are not in place to
1446	1446	25 ensure independence, insulation, oversight, and
1447	1447	26 transparency.
1448	1448
1449	1449
1450	1450
1451	1451
1452	1452
1453	1453	HB3779 - 40 - LRB104 11172 AAS 21254 b
1454	1454
1455	1455
1456	1456	HB3779- 41 -LRB104 11172 AAS 21254 b HB3779 - 41 - LRB104 11172 AAS 21254 b
1457	1457	HB3779 - 41 - LRB104 11172 AAS 21254 b
1458	1458	1 (12) The principles that underlie the procurement
1459	1459	2 reform legislation apply also in the context of power
1460	1460	3 purchasing.
1461	1461	4 (13) To ensure that the benefits of installing
1462	1462	5 renewable resources are available to all Illinois
1463	1463	6 residents and located across the State, subject to
1464	1464	7 appropriation, it is necessary for the Agency to provide
1465	1465	8 public information and educational resources on how
1466	1466	9 residents can benefit from the expansion of renewable
1467	1467	10 energy in Illinois and participate in the Illinois Solar
1468	1468	11 for All Program established in Section 1-56, the
1469	1469	12 Adjustable Block program established in Section 1-75, the
1470	1470	13 job training programs established by paragraph (1) of
1471	1471	14 subsection (a) of Section 16-108.12 of the Public
1472	1472	15 Utilities Act, and the programs and resources established
1473	1473	16 by the Energy Transition Act.
1474	1474	17 (14) To ensure the State's clean energy goals are
1475	1475	18 timely met and that reliable clean energy is produced and
1476	1476	19 available when customers need it, the Agency should begin
1477	1477	20 to procure clean power and encourage storage, including
1478	1478	21 through long-term contracts. Where the comparison shows
1479	1479	22 that clean products can be procured at or near the cost of
1480	1480	23 non-renewable products, the clean products should be
1481	1481	24 procured. This requirement will limit the State's
1482	1482	25 dependence on fossil generation and reduce the potential
1483	1483	26 need to import fossil-fueled power.
1484	1484
1485	1485
1486	1486
1487	1487
1488	1488
1489	1489	HB3779 - 41 - LRB104 11172 AAS 21254 b
1490	1490
1491	1491
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1493	1493	HB3779 - 42 - LRB104 11172 AAS 21254 b
1494	1494	1 The General Assembly therefore finds that it is necessary
1495	1495	2 to create the Illinois Power Agency and that the goals and
1496	1496	3 objectives of that Agency are to accomplish each of the
1497	1497	4 following:
1498	1498	5 (A) Develop electricity procurement plans to ensure
1499	1499	6 adequate, reliable, affordable, efficient, and
1500	1500	7 environmentally sustainable electric service at the lowest
1501	1501	8 total cost over time, taking into account any benefits of
1502	1502	9 price stability, for electric utilities that on December
1503	1503	10 31, 2005 provided electric service to at least 100,000
1504	1504	11 customers in Illinois and for small multi-jurisdictional
1505	1505	12 electric utilities that (i) on December 31, 2005 served
1506	1506	13 less than 100,000 customers in Illinois and (ii) request a
1507	1507	14 procurement plan for their Illinois jurisdictional load.
1508	1508	15 The procurement plan shall be updated on an annual basis
1509	1509	16 and shall include renewable energy resources and,
1510	1510	17 beginning with the delivery year commencing June 1, 2017,
1511	1511	18 zero emission credits from zero emission facilities
1512	1512	19 sufficient to achieve the standards specified in this Act.
1513	1513	20 (B) Conduct the competitive procurement processes
1514	1514	21 identified in this Act.
1515	1515	22 (C) Develop electric generation and co-generation
1516	1516	23 facilities that use indigenous coal or renewable
1517	1517	24 resources, or both, financed with bonds issued by the
1518	1518	25 Illinois Finance Authority.
1519	1519	26 (D) Supply electricity from the Agency's facilities at
1520	1520
1521	1521
1522	1522
1523	1523
1524	1524
1525	1525	HB3779 - 42 - LRB104 11172 AAS 21254 b
1526	1526
1527	1527
1528	1528	HB3779- 43 -LRB104 11172 AAS 21254 b HB3779 - 43 - LRB104 11172 AAS 21254 b
1529	1529	HB3779 - 43 - LRB104 11172 AAS 21254 b
1530	1530	1 cost to one or more of the following: municipal electric
1531	1531	2 systems, governmental aggregators, or rural electric
1532	1532	3 cooperatives in Illinois.
1533	1533	4 (E) Ensure that the process of power procurement is
1534	1534	5 conducted in an ethical and transparent fashion, immune
1535	1535	6 from improper influence.
1536	1536	7 (F) Continue to review its policies and practices to
1537	1537	8 determine how best to meet its mission of providing the
1538	1538	9 lowest cost power to the greatest number of people, at any
1539	1539	10 given point in time, in accordance with applicable law.
1540	1540	11 (G) Operate in a structurally insulated, independent,
1541	1541	12 and transparent fashion so that nothing impedes the
1542	1542	13 Agency's mission to secure power at the best prices the
1543	1543	14 market will bear, provided that the Agency meets all
1544	1544	15 applicable legal requirements.
1545	1545	16 (H) Implement renewable energy procurement and
1546	1546	17 training programs throughout the State to diversify
1547	1547	18 Illinois electricity supply, improve reliability, avoid
1548	1548	19 and reduce pollution, reduce peak demand, and enhance
1549	1549	20 public health and well-being of Illinois residents,
1550	1550	21 including low-income residents.
1551	1551	22 (Source: P.A. 102-662, eff. 9-15-21.)
1552	1552	23 (20 ILCS 3855/1-10)
1553	1553	24 Sec. 1-10. Definitions.
1554	1554	25 "Agency" means the Illinois Power Agency.
1555	1555
1556	1556
1557	1557
1558	1558
1559	1559
1560	1560	HB3779 - 43 - LRB104 11172 AAS 21254 b
1561	1561
1562	1562
1563	1563	HB3779- 44 -LRB104 11172 AAS 21254 b HB3779 - 44 - LRB104 11172 AAS 21254 b
1564	1564	HB3779 - 44 - LRB104 11172 AAS 21254 b
1565	1565	1 "Agency loan agreement" means any agreement pursuant to
1566	1566	2 which the Illinois Finance Authority agrees to loan the
1567	1567	3 proceeds of revenue bonds issued with respect to a project to
1568	1568	4 the Agency upon terms providing for loan repayment
1569	1569	5 installments at least sufficient to pay when due all principal
1570	1570	6 of, interest and premium, if any, on those revenue bonds, and
1571	1571	7 providing for maintenance, insurance, and other matters in
1572	1572	8 respect of the project.
1573	1573	9 "Authority" means the Illinois Finance Authority.
1574	1574	10 "Brownfield site photovoltaic project" means photovoltaics
1575	1575	11 that are either:
1576	1576	12 (1) interconnected to an electric utility as defined
1577	1577	13 in this Section, a municipal utility as defined in this
1578	1578	14 Section, a public utility as defined in Section 3-105 of
1579	1579	15 the Public Utilities Act, or an electric cooperative as
1580	1580	16 defined in Section 3-119 of the Public Utilities Act and
1581	1581	17 located at a site that is regulated by any of the following
1582	1582	18 entities under the following programs:
1583	1583	19 (A) the United States Environmental Protection
1584	1584	20 Agency under the federal Comprehensive Environmental
1585	1585	21 Response, Compensation, and Liability Act of 1980, as
1586	1586	22 amended;
1587	1587	23 (B) the United States Environmental Protection
1588	1588	24 Agency under the Corrective Action Program of the
1589	1589	25 federal Resource Conservation and Recovery Act, as
1590	1590	26 amended;
1591	1591
1592	1592
1593	1593
1594	1594
1595	1595
1596	1596	HB3779 - 44 - LRB104 11172 AAS 21254 b
1597	1597
1598	1598
1599	1599	HB3779- 45 -LRB104 11172 AAS 21254 b HB3779 - 45 - LRB104 11172 AAS 21254 b
1600	1600	HB3779 - 45 - LRB104 11172 AAS 21254 b
1601	1601	1 (C) the Illinois Environmental Protection Agency
1602	1602	2 under the Illinois Site Remediation Program; or
1603	1603	3 (D) the Illinois Environmental Protection Agency
1604	1604	4 under the Illinois Solid Waste Program; or
1605	1605	5 (2) located at the site of a coal mine that has
1606	1606	6 permanently ceased coal production, permanently halted any
1607	1607	7 re-mining operations, and is no longer accepting any coal
1608	1608	8 combustion residues; has both completed all clean-up and
1609	1609	9 remediation obligations under the federal Surface Mining
1610	1610	10 and Reclamation Act of 1977 and all applicable Illinois
1611	1611	11 rules and any other clean-up, remediation, or ongoing
1612	1612	12 monitoring to safeguard the health and well-being of the
1613	1613	13 people of the State of Illinois, as well as demonstrated
1614	1614	14 compliance with all applicable federal and State
1615	1615	15 environmental rules and regulations, including, but not
1616	1616	16 limited, to 35 Ill. Adm. Code Part 845 and any rules for
1617	1617	17 historic fill of coal combustion residuals, including any
1618	1618	18 rules finalized in Subdocket A of Illinois Pollution
1619	1619	19 Control Board docket R2020-019.
1620	1620	20 "Clean coal facility" means an electric generating
1621	1621	21 facility that uses primarily coal as a feedstock and that
1622	1622	22 captures and sequesters carbon dioxide emissions at the
1623	1623	23 following levels: at least 50% of the total carbon dioxide
1624	1624	24 emissions that the facility would otherwise emit if, at the
1625	1625	25 time construction commences, the facility is scheduled to
1626	1626	26 commence operation before 2016, at least 70% of the total
1627	1627
1628	1628
1629	1629
1630	1630
1631	1631
1632	1632	HB3779 - 45 - LRB104 11172 AAS 21254 b
1633	1633
1634	1634
1635	1635	HB3779- 46 -LRB104 11172 AAS 21254 b HB3779 - 46 - LRB104 11172 AAS 21254 b
1636	1636	HB3779 - 46 - LRB104 11172 AAS 21254 b
1637	1637	1 carbon dioxide emissions that the facility would otherwise
1638	1638	2 emit if, at the time construction commences, the facility is
1639	1639	3 scheduled to commence operation during 2016 or 2017, and at
1640	1640	4 least 90% of the total carbon dioxide emissions that the
1641	1641	5 facility would otherwise emit if, at the time construction
1642	1642	6 commences, the facility is scheduled to commence operation
1643	1643	7 after 2017. The power block of the clean coal facility shall
1644	1644	8 not exceed allowable emission rates for sulfur dioxide,
1645	1645	9 nitrogen oxides, carbon monoxide, particulates and mercury for
1646	1646	10 a natural gas-fired combined-cycle facility the same size as
1647	1647	11 and in the same location as the clean coal facility at the time
1648	1648	12 the clean coal facility obtains an approved air permit. All
1649	1649	13 coal used by a clean coal facility shall have high volatile
1650	1650	14 bituminous rank and greater than 1.7 pounds of sulfur per
1651	1651	15 million Btu content, unless the clean coal facility does not
1652	1652	16 use gasification technology and was operating as a
1653	1653	17 conventional coal-fired electric generating facility on June
1654	1654	18 1, 2009 (the effective date of Public Act 95-1027).
1655	1655	19 "Clean coal SNG brownfield facility" means a facility that
1656	1656	20 (1) has commenced construction by July 1, 2015 on an urban
1657	1657	21 brownfield site in a municipality with at least 1,000,000
1658	1658	22 residents; (2) uses a gasification process to produce
1659	1659	23 substitute natural gas; (3) uses coal as at least 50% of the
1660	1660	24 total feedstock over the term of any sourcing agreement with a
1661	1661	25 utility and the remainder of the feedstock may be either
1662	1662	26 petroleum coke or coal, with all such coal having a high
1663	1663
1664	1664
1665	1665
1666	1666
1667	1667
1668	1668	HB3779 - 46 - LRB104 11172 AAS 21254 b
1669	1669
1670	1670
1671	1671	HB3779- 47 -LRB104 11172 AAS 21254 b HB3779 - 47 - LRB104 11172 AAS 21254 b
1672	1672	HB3779 - 47 - LRB104 11172 AAS 21254 b
1673	1673	1 bituminous rank and greater than 1.7 pounds of sulfur per
1674	1674	2 million Btu content unless the facility reasonably determines
1675	1675	3 that it is necessary to use additional petroleum coke to
1676	1676	4 deliver additional consumer savings, in which case the
1677	1677	5 facility shall use coal for at least 35% of the total feedstock
1678	1678	6 over the term of any sourcing agreement; and (4) captures and
1679	1679	7 sequesters at least 85% of the total carbon dioxide emissions
1680	1680	8 that the facility would otherwise emit.
1681	1681	9 "Clean coal SNG facility" means a facility that uses a
1682	1682	10 gasification process to produce substitute natural gas, that
1683	1683	11 sequesters at least 90% of the total carbon dioxide emissions
1684	1684	12 that the facility would otherwise emit, that uses at least 90%
1685	1685	13 coal as a feedstock, with all such coal having a high
1686	1686	14 bituminous rank and greater than 1.7 pounds of sulfur per
1687	1687	15 million Btu content, and that has a valid and effective permit
1688	1688	16 to construct emission sources and air pollution control
1689	1689	17 equipment and approval with respect to the federal regulations
1690	1690	18 for Prevention of Significant Deterioration of Air Quality
1691	1691	19 (PSD) for the plant pursuant to the federal Clean Air Act;
1692	1692	20 provided, however, a clean coal SNG brownfield facility shall
1693	1693	21 not be a clean coal SNG facility.
1694	1694	22 "Clean energy" means energy generation that is 90% or
1695	1695	23 greater free of carbon dioxide emissions.
1696	1696	24 "Commission" means the Illinois Commerce Commission.
1697	1697	25 "Community renewable generation project" means an electric
1698	1698	26 generating facility that:
1699	1699
1700	1700
1701	1701
1702	1702
1703	1703
1704	1704	HB3779 - 47 - LRB104 11172 AAS 21254 b
1705	1705
1706	1706
1707	1707	HB3779- 48 -LRB104 11172 AAS 21254 b HB3779 - 48 - LRB104 11172 AAS 21254 b
1708	1708	HB3779 - 48 - LRB104 11172 AAS 21254 b
1709	1709	1 (1) is powered by wind, solar thermal energy,
1710	1710	2 photovoltaic cells or panels, biodiesel, crops and
1711	1711	3 untreated and unadulterated organic waste biomass, and
1712	1712	4 hydropower that does not involve new construction of dams;
1713	1713	5 (2) is interconnected at the distribution system level
1714	1714	6 of an electric utility as defined in this Section, a
1715	1715	7 municipal utility as defined in this Section that owns or
1716	1716	8 operates electric distribution facilities, a public
1717	1717	9 utility as defined in Section 3-105 of the Public
1718	1718	10 Utilities Act, or an electric cooperative, as defined in
1719	1719	11 Section 3-119 of the Public Utilities Act;
1720	1720	12 (3) credits the value of electricity generated by the
1721	1721	13 facility to the subscribers of the facility; and
1722	1722	14 (4) is limited in nameplate capacity to less than or
1723	1723	15 equal to 5,000 kilowatts.
1724	1724	16 "Costs incurred in connection with the development and
1725	1725	17 construction of a facility" means:
1726	1726	18 (1) the cost of acquisition of all real property,
1727	1727	19 fixtures, and improvements in connection therewith and
1728	1728	20 equipment, personal property, and other property, rights,
1729	1729	21 and easements acquired that are deemed necessary for the
1730	1730	22 operation and maintenance of the facility;
1731	1731	23 (2) financing costs with respect to bonds, notes, and
1732	1732	24 other evidences of indebtedness of the Agency;
1733	1733	25 (3) all origination, commitment, utilization,
1734	1734	26 facility, placement, underwriting, syndication, credit
1735	1735
1736	1736
1737	1737
1738	1738
1739	1739
1740	1740	HB3779 - 48 - LRB104 11172 AAS 21254 b
1741	1741
1742	1742
1743	1743	HB3779- 49 -LRB104 11172 AAS 21254 b HB3779 - 49 - LRB104 11172 AAS 21254 b
1744	1744	HB3779 - 49 - LRB104 11172 AAS 21254 b
1745	1745	1 enhancement, and rating agency fees;
1746	1746	2 (4) engineering, design, procurement, consulting,
1747	1747	3 legal, accounting, title insurance, survey, appraisal,
1748	1748	4 escrow, trustee, collateral agency, interest rate hedging,
1749	1749	5 interest rate swap, capitalized interest, contingency, as
1750	1750	6 required by lenders, and other financing costs, and other
1751	1751	7 expenses for professional services; and
1752	1752	8 (5) the costs of plans, specifications, site study and
1753	1753	9 investigation, installation, surveys, other Agency costs
1754	1754	10 and estimates of costs, and other expenses necessary or
1755	1755	11 incidental to determining the feasibility of any project,
1756	1756	12 together with such other expenses as may be necessary or
1757	1757	13 incidental to the financing, insuring, acquisition, and
1758	1758	14 construction of a specific project and starting up,
1759	1759	15 commissioning, and placing that project in operation.
1760	1760	16 "Delivery services" has the same definition as found in
1761	1761	17 Section 16-102 of the Public Utilities Act.
1762	1762	18 "Delivery year" means the consecutive 12-month period
1763	1763	19 beginning June 1 of a given year and ending May 31 of the
1764	1764	20 following year.
1765	1765	21 "Demand response" means measures that decrease peak
1766	1766	22 electricity demand or shift demand from peak to off-peak
1767	1767	23 periods.
1768	1768	24 "Department" means the Department of Commerce and Economic
1769	1769	25 Opportunity.
1770	1770	26 "Director" means the Director of the Illinois Power
1771	1771
1772	1772
1773	1773
1774	1774
1775	1775
1776	1776	HB3779 - 49 - LRB104 11172 AAS 21254 b
1777	1777
1778	1778
1779	1779	HB3779- 50 -LRB104 11172 AAS 21254 b HB3779 - 50 - LRB104 11172 AAS 21254 b
1780	1780	HB3779 - 50 - LRB104 11172 AAS 21254 b
1781	1781	1 Agency.
1782	1782	2 "Demand-response" means measures that decrease peak
1783	1783	3 electricity demand or shift demand from peak to off-peak
1784	1784	4 periods.
1785	1785	5 "Distributed renewable energy generation device" means a
1786	1786	6 device that is:
1787	1787	7 (1) powered by wind, solar thermal energy,
1788	1788	8 photovoltaic cells or panels, biodiesel, crops and
1789	1789	9 untreated and unadulterated organic waste biomass, tree
1790	1790	10 waste, and hydropower that does not involve new
1791	1791	11 construction of dams, waste heat to power systems, or
1792	1792	12 qualified combined heat and power systems;
1793	1793	13 (2) interconnected at the distribution system level of
1794	1794	14 either an electric utility as defined in this Section, a
1795	1795	15 municipal utility as defined in this Section that owns or
1796	1796	16 operates electric distribution facilities, or a rural
1797	1797	17 electric cooperative as defined in Section 3-119 of the
1798	1798	18 Public Utilities Act;
1799	1799	19 (3) located on the customer side of the customer's
1800	1800	20 electric meter and is primarily used to offset that
1801	1801	21 customer's electricity load; and
1802	1802	22 (4) (blank).
1803	1803	23 "Electric utility" has the same definition as found in
1804	1804	24 Section 16-102 of the Public Utilities Act.
1805	1805	25 "Energy efficiency" means measures that reduce the amount
1806	1806	26 of electricity or natural gas consumed in order to achieve a
1807	1807
1808	1808
1809	1809
1810	1810
1811	1811
1812	1812	HB3779 - 50 - LRB104 11172 AAS 21254 b
1813	1813
1814	1814
1815	1815	HB3779- 51 -LRB104 11172 AAS 21254 b HB3779 - 51 - LRB104 11172 AAS 21254 b
1816	1816	HB3779 - 51 - LRB104 11172 AAS 21254 b
1817	1817	1 given end use. "Energy efficiency" includes voltage
1818	1818	2 optimization measures that optimize the voltage at points on
1819	1819	3 the electric distribution voltage system and thereby reduce
1820	1820	4 electricity consumption by electric customers' end use
1821	1821	5 devices. "Energy efficiency" also includes measures that
1822	1822	6 reduce the total Btus of electricity, natural gas, and other
1823	1823	7 fuels needed to meet the end use or uses.
1824	1824	8 "Energy storage resources" means commitments from the
1825	1825	9 energy storage systems to serve Illinois energy resource and
1826	1826	10 security needs as identified in the energy storage procurement
1827	1827	11 plan. "Energy storage resources" may include intangible
1828	1828	12 attributes, tolling agreements, or other mechanisms used to
1829	1829	13 incentivize successful energy storage system development.
1830	1830	14 "Energy storage system" means commercially available
1831	1831	15 technology that is capable of absorbing energy and storing it
1832	1832	16 for use at a later time, including, but not limited to,
1833	1833	17 electrochemical and electromechanical technologies. "Energy
1834	1834	18 storage system" does not include technologies that require
1835	1835	19 combustion.
1836	1836	20 "Energy storage system capacity" means the nameplate
1837	1837	21 capacity of a contracted energy storage system, measured in
1838	1838	22 megawatts of alternating current.
1839	1839	23 "Equity eligible contractor" means a business that is
1840	1840	24 majority-owned by eligible persons, or a nonprofit or
1841	1841	25 cooperative that is majority-governed by eligible persons, or
1842	1842	26 is a natural person that is an eligible person offering
1843	1843
1844	1844
1845	1845
1846	1846
1847	1847
1848	1848	HB3779 - 51 - LRB104 11172 AAS 21254 b
1849	1849
1850	1850
1851	1851	HB3779- 52 -LRB104 11172 AAS 21254 b HB3779 - 52 - LRB104 11172 AAS 21254 b
1852	1852	HB3779 - 52 - LRB104 11172 AAS 21254 b
1853	1853	1 personal services as an independent contractor.
1854	1854	2 "Equity eligible persons" or "eligible persons" means
1855	1855	3 persons who would most benefit from equitable investments by
1856	1856	4 the State designed to combat discrimination, specifically: (1)
1857	1857	5 persons who graduate from or are current or former
1858	1858	6 participants in the Clean Jobs Workforce Network Program, the
1859	1859	7 Clean Energy Contractor Incubator Program, the Illinois
1860	1860	8 Climate Works Preapprenticeship Program, Returning Residents
1861	1861	9 Clean Jobs Training Program, or the Clean Energy Primes
1862	1862	10 Contractor Accelerator Program, and the solar training
1863	1863	11 pipeline and multi-cultural jobs program created in paragraphs
1864	1864	12 (a)(1) and (a)(3) of Section 16-108.12 of the Public Utilities
1865	1865	13 Act; (2) persons who are graduates of or currently enrolled in
1866	1866	14 the foster care system; (3) persons who were formerly
1867	1867	15 incarcerated; (4) persons whose primary residence is in an
1868	1868	16 equity investment eligible community.
1869	1869	17 "Electric utility" has the same definition as found in
1870	1870	18 Section 16-102 of the Public Utilities Act.
1871	1871	19 "Equity investment eligible community" or "eligible
1872	1872	20 community" are synonymous and mean the geographic areas
1873	1873	21 throughout Illinois which would most benefit from equitable
1874	1874	22 investments by the State designed to combat discrimination.
1875	1875	23 Specifically, the eligible communities shall be defined as the
1876	1876	24 following areas:
1877	1877	25 (1) R3 Areas as established pursuant to Section 10-40
1878	1878	26 of the Cannabis Regulation and Tax Act, where residents
1879	1879
1880	1880
1881	1881
1882	1882
1883	1883
1884	1884	HB3779 - 52 - LRB104 11172 AAS 21254 b
1885	1885
1886	1886
1887	1887	HB3779- 53 -LRB104 11172 AAS 21254 b HB3779 - 53 - LRB104 11172 AAS 21254 b
1888	1888	HB3779 - 53 - LRB104 11172 AAS 21254 b
1889	1889	1 have historically been excluded from economic
1890	1890	2 opportunities, including opportunities in the energy
1891	1891	3 sector; and
1892	1892	4 (2) environmental justice communities, as defined by
1893	1893	5 the Illinois Power Agency pursuant to the Illinois Power
1894	1894	6 Agency Act, where residents have historically been subject
1895	1895	7 to disproportionate burdens of pollution, including
1896	1896	8 pollution from the energy sector.
1897	1897	9 "Equity eligible persons" or "eligible persons" means
1898	1898	10 persons who would most benefit from equitable investments by
1899	1899	11 the State designed to combat discrimination, specifically:
1900	1900	12 (1) persons who graduate from or are current or former
1901	1901	13 participants in the Clean Jobs Workforce Network Program,
1902	1902	14 the Clean Energy Contractor Incubator Program, the
1903	1903	15 Illinois Climate Works Preapprenticeship Program,
1904	1904	16 Returning Residents Clean Jobs Training Program, or the
1905	1905	17 Clean Energy Primes Contractor Accelerator Program, and
1906	1906	18 the solar training pipeline and multi-cultural jobs
1907	1907	19 program created in paragraphs (a)(1) and (a)(3) of Section
1908	1908	20 16-208.12 of the Public Utilities Act;
1909	1909	21 (2) persons who are graduates of or currently enrolled
1910	1910	22 in the foster care system;
1911	1911	23 (3) persons who were formerly incarcerated;
1912	1912	24 (4) persons whose primary residence is in an equity
1913	1913	25 investment eligible community.
1914	1914	26 "Equity eligible contractor" means a business that is
1915	1915
1916	1916
1917	1917
1918	1918
1919	1919
1920	1920	HB3779 - 53 - LRB104 11172 AAS 21254 b
1921	1921
1922	1922
1923	1923	HB3779- 54 -LRB104 11172 AAS 21254 b HB3779 - 54 - LRB104 11172 AAS 21254 b
1924	1924	HB3779 - 54 - LRB104 11172 AAS 21254 b
1925	1925	1 majority-owned by eligible persons, or a nonprofit or
1926	1926	2 cooperative that is majority-governed by eligible persons, or
1927	1927	3 is a natural person that is an eligible person offering
1928	1928	4 personal services as an independent contractor.
1929	1929	5 "Facility" means an electric generating unit or a
1930	1930	6 co-generating unit that produces electricity along with
1931	1931	7 related equipment necessary to connect the facility to an
1932	1932	8 electric transmission or distribution system.
1933	1933	9 "General contractor" means the entity or organization with
1934	1934	10 main responsibility for the building of a construction project
1935	1935	11 and who is the party signing the prime construction contract
1936	1936	12 for the project.
1937	1937	13 "Governmental aggregator" means one or more units of local
1938	1938	14 government that individually or collectively procure
1939	1939	15 electricity to serve residential retail electrical loads
1940	1940	16 located within its or their jurisdiction.
1941	1941	17 "High voltage direct current converter station" means the
1942	1942	18 collection of equipment that converts direct current energy
1943	1943	19 from a high voltage direct current transmission line into
1944	1944	20 alternating current using Voltage Source Conversion technology
1945	1945	21 and that is interconnected with transmission or distribution
1946	1946	22 assets located in Illinois.
1947	1947	23 "High voltage direct current renewable energy credit"
1948	1948	24 means a renewable energy credit associated with a renewable
1949	1949	25 energy resource where the renewable energy resource has
1950	1950	26 entered into a contract to transmit the energy associated with
1951	1951
1952	1952
1953	1953
1954	1954
1955	1955
1956	1956	HB3779 - 54 - LRB104 11172 AAS 21254 b
1957	1957
1958	1958
1959	1959	HB3779- 55 -LRB104 11172 AAS 21254 b HB3779 - 55 - LRB104 11172 AAS 21254 b
1960	1960	HB3779 - 55 - LRB104 11172 AAS 21254 b
1961	1961	1 such renewable energy credit over high voltage direct current
1962	1962	2 transmission facilities.
1963	1963	3 "High voltage direct current transmission facilities"
1964	1964	4 means the collection of installed equipment that converts
1965	1965	5 alternating current energy in one location to direct current
1966	1966	6 and transmits that direct current energy to a high voltage
1967	1967	7 direct current converter station using Voltage Source
1968	1968	8 Conversion technology. "High voltage direct current
1969	1969	9 transmission facilities" includes the high voltage direct
1970	1970	10 current converter station itself and associated high voltage
1971	1971	11 direct current transmission lines. Notwithstanding the
1972	1972	12 preceding, after September 15, 2021 (the effective date of
1973	1973	13 Public Act 102-662), an otherwise qualifying collection of
1974	1974	14 equipment does not qualify as high voltage direct current
1975	1975	15 transmission facilities unless its developer entered into a
1976	1976	16 project labor agreement, is capable of transmitting
1977	1977	17 electricity at 525kv with an Illinois converter station
1978	1978	18 located and interconnected in the region of the PJM
1979	1979	19 Interconnection, LLC, and the system does not operate as a
1980	1980	20 public utility, as that term is defined in Section 3-105 of the
1981	1981	21 Public Utilities Act.
1982	1982	22 "Hydropower" means any method of electricity generation or
1983	1983	23 storage that results from the flow of water, including
1984	1984	24 impoundment facilities, diversion facilities, and pumped
1985	1985	25 storage facilities.
1986	1986	26 "Index price" means the real-time energy settlement price
1987	1987
1988	1988
1989	1989
1990	1990
1991	1991
1992	1992	HB3779 - 55 - LRB104 11172 AAS 21254 b
1993	1993
1994	1994
1995	1995	HB3779- 56 -LRB104 11172 AAS 21254 b HB3779 - 56 - LRB104 11172 AAS 21254 b
1996	1996	HB3779 - 56 - LRB104 11172 AAS 21254 b
1997	1997	1 at the applicable Illinois trading hub, such as PJM-NIHUB or
1998	1998	2 MISO-IL, for a given settlement period.
1999	1999	3 "Indexed renewable energy credit" means a tradable credit
2000	2000	4 that represents the environmental attributes of one megawatt
2001	2001	5 hour of energy produced from a renewable energy resource, the
2002	2002	6 price of which shall be calculated by subtracting the strike
2003	2003	7 price offered by a new utility-scale wind project or a new
2004	2004	8 utility-scale photovoltaic project from the index price in a
2005	2005	9 given settlement period.
2006	2006	10 "Indexed renewable energy credit counterparty" has the
2007	2007	11 same meaning as "public utility" as defined in Section 3-105
2008	2008	12 of the Public Utilities Act.
2009	2009	13 "Local government" means a unit of local government as
2010	2010	14 defined in Section 1 of Article VII of the Illinois
2011	2011	15 Constitution.
2012	2012	16 "Modernized" or "retooled" means the construction, repair,
2013	2013	17 maintenance, or significant expansion of turbines and existing
2014	2014	18 hydropower dams.
2015	2015	19 "Municipality" means a city, village, or incorporated
2016	2016	20 town.
2017	2017	21 "Municipal utility" means a public utility owned and
2018	2018	22 operated by any subdivision or municipal corporation of this
2019	2019	23 State.
2020	2020	24 "Nameplate capacity" means the aggregate inverter
2021	2021	25 nameplate capacity in kilowatts AC.
2022	2022	26 "Person" means any natural person, firm, partnership,
2023	2023
2024	2024
2025	2025
2026	2026
2027	2027
2028	2028	HB3779 - 56 - LRB104 11172 AAS 21254 b
2029	2029
2030	2030
2031	2031	HB3779- 57 -LRB104 11172 AAS 21254 b HB3779 - 57 - LRB104 11172 AAS 21254 b
2032	2032	HB3779 - 57 - LRB104 11172 AAS 21254 b
2033	2033	1 corporation, either domestic or foreign, company, association,
2034	2034	2 limited liability company, joint stock company, or association
2035	2035	3 and includes any trustee, receiver, assignee, or personal
2036	2036	4 representative thereof.
2037	2037	5 "Project" means the planning, bidding, and construction of
2038	2038	6 a facility.
2039	2039	7 "Project labor agreement" means a pre-hire collective
2040	2040	8 bargaining agreement that covers all terms and conditions of
2041	2041	9 employment on a specific construction project and must include
2042	2042	10 the following:
2043	2043	11 (1) provisions establishing the minimum hourly wage
2044	2044	12 for each class of labor organization employee;
2045	2045	13 (2) provisions establishing the benefits and other
2046	2046	14 compensation for each class of labor organization
2047	2047	15 employee;
2048	2048	16 (3) provisions establishing that no strike or disputes
2049	2049	17 will be engaged in by the labor organization employees;
2050	2050	18 (4) provisions establishing that no lockout or
2051	2051	19 disputes will be engaged in by the general contractor
2052	2052	20 building the project; and
2053	2053	21 (5) provisions for minorities and women, as defined
2054	2054	22 under the Business Enterprise for Minorities, Women, and
2055	2055	23 Persons with Disabilities Act, setting forth goals for
2056	2056	24 apprenticeship hours to be performed by minorities and
2057	2057	25 women and setting forth goals for total hours to be
2058	2058	26 performed by underrepresented minorities and women.
2059	2059
2060	2060
2061	2061
2062	2062
2063	2063
2064	2064	HB3779 - 57 - LRB104 11172 AAS 21254 b
2065	2065
2066	2066
2067	2067	HB3779- 58 -LRB104 11172 AAS 21254 b HB3779 - 58 - LRB104 11172 AAS 21254 b
2068	2068	HB3779 - 58 - LRB104 11172 AAS 21254 b
2069	2069	1 A labor organization and the general contractor building
2070	2070	2 the project shall have the authority to include other terms
2071	2071	3 and conditions as they deem necessary.
2072	2072	4 "Public utility" has the same definition as found in
2073	2073	5 Section 3-105 of the Public Utilities Act.
2074	2074	6 "Qualified combined heat and power systems" means systems
2075	2075	7 that, either simultaneously or sequentially, produce
2076	2076	8 electricity and useful thermal energy from a single fuel
2077	2077	9 source. Such systems are eligible for "renewable energy
2078	2078	10 credits" in an amount equal to its total energy output where a
2079	2079	11 renewable fuel is consumed or in an amount equal to the net
2080	2080	12 reduction in nonrenewable fuel consumed on a total energy
2081	2081	13 output basis.
2082	2082	14 "Real property" means any interest in land together with
2083	2083	15 all structures, fixtures, and improvements thereon, including
2084	2084	16 lands under water and riparian rights, any easements,
2085	2085	17 covenants, licenses, leases, rights-of-way, uses, and other
2086	2086	18 interests, together with any liens, judgments, mortgages, or
2087	2087	19 other claims or security interests related to real property.
2088	2088	20 "Renewable energy credit" means a tradable credit that
2089	2089	21 represents the environmental attributes of one megawatt hour
2090	2090	22 of energy produced from a renewable energy resource.
2091	2091	23 "Renewable energy resources" includes energy and its
2092	2092	24 associated renewable energy credit or renewable energy credits
2093	2093	25 from wind, solar thermal energy, photovoltaic cells and
2094	2094	26 panels, biodiesel, anaerobic digestion, crops and untreated
2095	2095
2096	2096
2097	2097
2098	2098
2099	2099
2100	2100	HB3779 - 58 - LRB104 11172 AAS 21254 b
2101	2101
2102	2102
2103	2103	HB3779- 59 -LRB104 11172 AAS 21254 b HB3779 - 59 - LRB104 11172 AAS 21254 b
2104	2104	HB3779 - 59 - LRB104 11172 AAS 21254 b
2105	2105	1 and unadulterated organic waste biomass, and hydropower that
2106	2106	2 does not involve new construction of dams, waste heat to power
2107	2107	3 systems, or qualified combined heat and power systems. For
2108	2108	4 purposes of this Act, landfill gas produced in the State is
2109	2109	5 considered a renewable energy resource. "Renewable energy
2110	2110	6 resources" does not include the incineration or burning of
2111	2111	7 tires, garbage, general household, institutional, and
2112	2112	8 commercial waste, industrial lunchroom or office waste,
2113	2113	9 landscape waste, railroad crossties, utility poles, or
2114	2114	10 construction or demolition debris, other than untreated and
2115	2115	11 unadulterated waste wood. "Renewable energy resources" also
2116	2116	12 includes high voltage direct current renewable energy credits
2117	2117	13 and the associated energy converted to alternating current by
2118	2118	14 a high voltage direct current converter station to the extent
2119	2119	15 that: (1) the generator of such renewable energy resource
2120	2120	16 contracted with a third party to transmit the energy over the
2121	2121	17 high voltage direct current transmission facilities, and (2)
2122	2122	18 the third-party contracting for delivery of renewable energy
2123	2123	19 resources over the high voltage direct current transmission
2124	2124	20 facilities have ownership rights over the unretired associated
2125	2125	21 high voltage direct current renewable energy credit.
2126	2126	22 "Retail customer" has the same definition as found in
2127	2127	23 Section 16-102 of the Public Utilities Act.
2128	2128	24 "Revenue bond" means any bond, note, or other evidence of
2129	2129	25 indebtedness issued by the Authority, the principal and
2130	2130	26 interest of which is payable solely from revenues or income
2131	2131
2132	2132
2133	2133
2134	2134
2135	2135
2136	2136	HB3779 - 59 - LRB104 11172 AAS 21254 b
2137	2137
2138	2138
2139	2139	HB3779- 60 -LRB104 11172 AAS 21254 b HB3779 - 60 - LRB104 11172 AAS 21254 b
2140	2140	HB3779 - 60 - LRB104 11172 AAS 21254 b
2141	2141	1 derived from any project or activity of the Agency.
2142	2142	2 "Sequester" means permanent storage of carbon dioxide by
2143	2143	3 injecting it into a saline aquifer, a depleted gas reservoir,
2144	2144	4 or an oil reservoir, directly or through an enhanced oil
2145	2145	5 recovery process that may involve intermediate storage,
2146	2146	6 regardless of whether these activities are conducted by a
2147	2147	7 clean coal facility, a clean coal SNG facility, a clean coal
2148	2148	8 SNG brownfield facility, or a party with which a clean coal
2149	2149	9 facility, clean coal SNG facility, or clean coal SNG
2150	2150	10 brownfield facility has contracted for such purposes.
2151	2151	11 "Service area" has the same definition as found in Section
2152	2152	12 16-102 of the Public Utilities Act.
2153	2153	13 "Settlement period" means the period of time utilized by
2154	2154	14 MISO and PJM and their successor organizations as the basis
2155	2155	15 for settlement calculations in the real-time energy market.
2156	2156	16 "Sourcing agreement" means (i) in the case of an electric
2157	2157	17 utility, an agreement between the owner of a clean coal
2158	2158	18 facility and such electric utility, which agreement shall have
2159	2159	19 terms and conditions meeting the requirements of paragraph (3)
2160	2160	20 of subsection (d) of Section 1-75, (ii) in the case of an
2161	2161	21 alternative retail electric supplier, an agreement between the
2162	2162	22 owner of a clean coal facility and such alternative retail
2163	2163	23 electric supplier, which agreement shall have terms and
2164	2164	24 conditions meeting the requirements of Section 16-115(d)(5) of
2165	2165	25 the Public Utilities Act, and (iii) in case of a gas utility,
2166	2166	26 an agreement between the owner of a clean coal SNG brownfield
2167	2167
2168	2168
2169	2169
2170	2170
2171	2171
2172	2172	HB3779 - 60 - LRB104 11172 AAS 21254 b
2173	2173
2174	2174
2175	2175	HB3779- 61 -LRB104 11172 AAS 21254 b HB3779 - 61 - LRB104 11172 AAS 21254 b
2176	2176	HB3779 - 61 - LRB104 11172 AAS 21254 b
2177	2177	1 facility and the gas utility, which agreement shall have the
2178	2178	2 terms and conditions meeting the requirements of subsection
2179	2179	3 (h-1) of Section 9-220 of the Public Utilities Act.
2180	2180	4 "Strike price" means a contract price for energy and
2181	2181	5 renewable energy credits from a new utility-scale wind project
2182	2182	6 or a new utility-scale photovoltaic project.
2183	2183	7 "Subscriber" means a person who (i) takes delivery service
2184	2184	8 from an electric utility, and (ii) has a subscription of no
2185	2185	9 less than 200 watts to a community renewable generation
2186	2186	10 project that is located in the electric utility's service
2187	2187	11 area. No subscriber's subscriptions may total more than 40% of
2188	2188	12 the nameplate capacity of an individual community renewable
2189	2189	13 generation project. Entities that are affiliated by virtue of
2190	2190	14 a common parent shall not represent multiple subscriptions
2191	2191	15 that total more than 40% of the nameplate capacity of an
2192	2192	16 individual community renewable generation project.
2193	2193	17 "Subscription" means an interest in a community renewable
2194	2194	18 generation project expressed in kilowatts, which is sized
2195	2195	19 primarily to offset part or all of the subscriber's
2196	2196	20 electricity usage.
2197	2197	21 "Substitute natural gas" or "SNG" means a gas manufactured
2198	2198	22 by gasification of hydrocarbon feedstock, which is
2199	2199	23 substantially interchangeable in use and distribution with
2200	2200	24 conventional natural gas.
2201	2201	25 "Total resource cost test" or "TRC test" means a standard
2202	2202	26 that is met if, for an investment in energy efficiency or
2203	2203
2204	2204
2205	2205
2206	2206
2207	2207
2208	2208	HB3779 - 61 - LRB104 11172 AAS 21254 b
2209	2209
2210	2210
2211	2211	HB3779- 62 -LRB104 11172 AAS 21254 b HB3779 - 62 - LRB104 11172 AAS 21254 b
2212	2212	HB3779 - 62 - LRB104 11172 AAS 21254 b
2213	2213	1 demand-response measures, the benefit-cost ratio is greater
2214	2214	2 than one. The benefit-cost ratio is the ratio of the net
2215	2215	3 present value of the total benefits of the program to the net
2216	2216	4 present value of the total costs as calculated over the
2217	2217	5 lifetime of the measures. A total resource cost test compares
2218	2218	6 the sum of avoided electric utility costs, representing the
2219	2219	7 benefits that accrue to the system and the participant in the
2220	2220	8 delivery of those efficiency measures and including avoided
2221	2221	9 costs associated with reduced use of natural gas or other
2222	2222	10 fuels, avoided costs associated with reduced water
2223	2223	11 consumption, and avoided costs associated with reduced
2224	2224	12 operation and maintenance costs, avoided societal costs
2225	2225	13 associated with reductions in greenhouse gas emissions, as
2226	2226	14 well as other quantifiable societal benefits, to the sum of
2227	2227	15 all incremental costs of end-use measures that are implemented
2228	2228	16 due to the program (including both utility and participant
2229	2229	17 contributions), plus costs to administer, deliver, and
2230	2230	18 evaluate each demand-side program, to quantify the net savings
2231	2231	19 obtained by substituting the demand-side program for supply
2232	2232	20 resources. The societal costs associated with greenhouse gas
2233	2233	21 emissions shall be assumed to be the greater of (i) $200 per
2234	2234	22 short ton, expressed in 2025 dollars, or (ii) the most
2235	2235	23 recently approved estimate developed by the federal government
2236	2236	24 using a real discount rate consistent with long-term Treasury
2237	2237	25 bond yields. Changes in greenhouse emissions from changes in
2238	2238	26 electricity consumption shall be estimated using long-run
2239	2239
2240	2240
2241	2241
2242	2242
2243	2243
2244	2244	HB3779 - 62 - LRB104 11172 AAS 21254 b
2245	2245
2246	2246
2247	2247	HB3779- 63 -LRB104 11172 AAS 21254 b HB3779 - 63 - LRB104 11172 AAS 21254 b
2248	2248	HB3779 - 63 - LRB104 11172 AAS 21254 b
2249	2249	1 marginal emissions rates developed by the National Renewable
2250	2250	2 Energy Laboratory's Cambium model or other Illinois-specific
2251	2251	3 modeling of comparable analytical rigor. In calculating
2252	2252	4 avoided costs of power and energy that an electric utility
2253	2253	5 would otherwise have had to acquire, reasonable estimates
2254	2254	6 shall be included of financial costs likely to be imposed by
2255	2255	7 future regulations and legislation on emissions of greenhouse
2256	2256	8 gases. In discounting future societal costs and benefits for
2257	2257	9 the purpose of calculating net present values, a societal
2258	2258	10 discount rate based on actual, long-term Treasury bond yields
2259	2259	11 should be used. Notwithstanding anything to the contrary, the
2260	2260	12 TRC test shall not include or take into account a calculation
2261	2261	13 of market price suppression effects or demand reduction
2262	2262	14 induced price effects.
2263	2263	15 "Utility-scale solar project" means an electric generating
2264	2264	16 facility that:
2265	2265	17 (1) generates electricity using photovoltaic cells;
2266	2266	18 and
2267	2267	19 (2) has a nameplate capacity that is greater than
2268	2268	20 5,000 kilowatts.
2269	2269	21 "Utility-scale wind project" means an electric generating
2270	2270	22 facility that:
2271	2271	23 (1) generates electricity using wind; and
2272	2272	24 (2) has a nameplate capacity that is greater than
2273	2273	25 5,000 kilowatts.
2274	2274	26 "Waste Heat to Power Systems" means systems that capture
2275	2275
2276	2276
2277	2277
2278	2278
2279	2279
2280	2280	HB3779 - 63 - LRB104 11172 AAS 21254 b
2281	2281
2282	2282
2283	2283	HB3779- 64 -LRB104 11172 AAS 21254 b HB3779 - 64 - LRB104 11172 AAS 21254 b
2284	2284	HB3779 - 64 - LRB104 11172 AAS 21254 b
2285	2285	1 and generate electricity from energy that would otherwise be
2286	2286	2 lost to the atmosphere without the use of additional fuel.
2287	2287	3 "Zero emission credit" means a tradable credit that
2288	2288	4 represents the environmental attributes of one megawatt hour
2289	2289	5 of energy produced from a zero emission facility.
2290	2290	6 "Zero emission facility" means a facility that: (1) is
2291	2291	7 fueled by nuclear power; and (2) is interconnected with PJM
2292	2292	8 Interconnection, LLC or the Midcontinent Independent System
2293	2293	9 Operator, Inc., or their successors.
2294	2294	10 (Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-28-23;
2295	2295	11 103-380, eff. 1-1-24.)
2296	2296	12 (20 ILCS 3855/1-20)
2297	2297	13 Sec. 1-20. General powers and duties of the Agency.
2298	2298	14 (a) The Agency is authorized to do each of the following:
2299	2299	15 (1) Develop electricity procurement plans to ensure
2300	2300	16 adequate, reliable, affordable, efficient, and
2301	2301	17 environmentally sustainable electric service at the lowest
2302	2302	18 total cost over time, taking into account any benefits of
2303	2303	19 price stability, for electric utilities that on December
2304	2304	20 31, 2005 provided electric service to at least 100,000
2305	2305	21 customers in Illinois and for small multi-jurisdictional
2306	2306	22 electric utilities that (A) on December 31, 2005 served
2307	2307	23 less than 100,000 customers in Illinois and (B) request a
2308	2308	24 procurement plan for their Illinois jurisdictional load.
2309	2309	25 Except as provided in paragraph (1.5) of this subsection
2310	2310
2311	2311
2312	2312
2313	2313
2314	2314
2315	2315	HB3779 - 64 - LRB104 11172 AAS 21254 b
2316	2316
2317	2317
2318	2318	HB3779- 65 -LRB104 11172 AAS 21254 b HB3779 - 65 - LRB104 11172 AAS 21254 b
2319	2319	HB3779 - 65 - LRB104 11172 AAS 21254 b
2320	2320	1 (a), the electricity procurement plans shall be updated on
2321	2321	2 an annual basis and shall include electricity generated
2322	2322	3 from renewable resources sufficient to achieve the
2323	2323	4 standards specified in this Act. Beginning with the
2324	2324	5 delivery year commencing June 1, 2017, develop procurement
2325	2325	6 plans to include zero emission credits generated from zero
2326	2326	7 emission facilities sufficient to achieve the standards
2327	2327	8 specified in this Act. Beginning with the delivery year
2328	2328	9 commencing on June 1, 2022, the Agency is authorized to
2329	2329	10 develop carbon mitigation credit procurement plans to
2330	2330	11 include carbon mitigation credits generated from
2331	2331	12 carbon-free energy resources sufficient to achieve the
2332	2332	13 standards specified in this Act.
2333	2333	14 (1.5) Develop a long-term renewable resources
2334	2334	15 procurement plan in accordance with subsection (c) of
2335	2335	16 Section 1-75 of this Act for renewable energy credits in
2336	2336	17 amounts sufficient to achieve the standards specified in
2337	2337	18 this Act for delivery years commencing June 1, 2017 and
2338	2338	19 for the programs and renewable energy credits specified in
2339	2339	20 Section 1-56 of this Act. Electricity procurement plans
2340	2340	21 for delivery years commencing after May 31, 2017, shall
2341	2341	22 not include procurement of renewable energy resources.
2342	2342	23 (2) Conduct competitive procurement processes to
2343	2343	24 procure the supply resources identified in the electricity
2344	2344	25 procurement plan, pursuant to Section 16-111.5 of the
2345	2345	26 Public Utilities Act, and, for the delivery year
2346	2346
2347	2347
2348	2348
2349	2349
2350	2350
2351	2351	HB3779 - 65 - LRB104 11172 AAS 21254 b
2352	2352
2353	2353
2354	2354	HB3779- 66 -LRB104 11172 AAS 21254 b HB3779 - 66 - LRB104 11172 AAS 21254 b
2355	2355	HB3779 - 66 - LRB104 11172 AAS 21254 b
2356	2356	1 commencing June 1, 2017, conduct procurement processes to
2357	2357	2 procure zero emission credits from zero emission
2358	2358	3 facilities, under subsection (d-5) of Section 1-75 of this
2359	2359	4 Act. For the delivery year commencing June 1, 2022, the
2360	2360	5 Agency is authorized to conduct procurement processes to
2361	2361	6 procure carbon mitigation credits from carbon-free energy
2362	2362	7 resources, under subsection (d-10) of Section 1-75 of this
2363	2363	8 Act.
2364	2364	9 (2.5) Beginning with the procurement for the 2017
2365	2365	10 delivery year, conduct competitive procurement processes
2366	2366	11 and implement programs to procure renewable energy credits
2367	2367	12 identified in the long-term renewable resources
2368	2368	13 procurement plan developed and approved under subsection
2369	2369	14 (c) of Section 1-75 of this Act and Section 16-111.5 of the
2370	2370	15 Public Utilities Act.
2371	2371	16 (2.10) Oversee the procurement by electric utilities
2372	2372	17 that served more than 300,000 customers in this State as
2373	2373	18 of January 1, 2019 of renewable energy credits from new
2374	2374	19 renewable energy facilities to be installed, along with
2375	2375	20 energy storage facilities, at or adjacent to the sites of
2376	2376	21 electric generating facilities that burned coal as their
2377	2377	22 primary fuel source as of January 1, 2016 in accordance
2378	2378	23 with subsection (c-5) of Section 1-75 of this Act.
2379	2379	24 (2.15) Oversee the procurement by electric utilities
2380	2380	25 of renewable energy credits from newly modernized or
2381	2381	26 retooled hydropower dams or dams that have been converted
2382	2382
2383	2383
2384	2384
2385	2385
2386	2386
2387	2387	HB3779 - 66 - LRB104 11172 AAS 21254 b
2388	2388
2389	2389
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2391	2391	HB3779 - 67 - LRB104 11172 AAS 21254 b
2392	2392	1 to support hydropower generation.
2393	2393	2 (3) Develop electric generation and co-generation
2394	2394	3 facilities that use indigenous coal or renewable
2395	2395	4 resources, or both, financed with bonds issued by the
2396	2396	5 Illinois Finance Authority.
2397	2397	6 (4) Supply electricity from the Agency's facilities at
2398	2398	7 cost to one or more of the following: municipal electric
2399	2399	8 systems, governmental aggregators, or rural electric
2400	2400	9 cooperatives in Illinois.
2401	2401	10 (5) Conduct an initial forward procurement and develop
2402	2402	11 an energy storage procurement plan in accordance with
2403	2403	12 Section 1-93 of this Act and Section 16-111.5 of the
2404	2404	13 Public Utilities Act, and conduct competitive procurement
2405	2405	14 processes and implement programs to procure energy storage
2406	2406	15 resources as identified in the energy storage procurement
2407	2407	16 plan as developed and approved under Section 1-93 of this
2408	2408	17 Act and Section 16-111.5 of the Public Utilities Act.
2409	2409	18 (b) Except as otherwise limited by this Act, the Agency
2410	2410	19 has all of the powers necessary or convenient to carry out the
2411	2411	20 purposes and provisions of this Act, including without
2412	2412	21 limitation, each of the following:
2413	2413	22 (1) To have a corporate seal, and to alter that seal at
2414	2414	23 pleasure, and to use it by causing it or a facsimile to be
2415	2415	24 affixed or impressed or reproduced in any other manner.
2416	2416	25 (2) To use the services of the Illinois Finance
2417	2417	26 Authority necessary to carry out the Agency's purposes.
2418	2418
2419	2419
2420	2420
2421	2421
2422	2422
2423	2423	HB3779 - 67 - LRB104 11172 AAS 21254 b
2424	2424
2425	2425
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2427	2427	HB3779 - 68 - LRB104 11172 AAS 21254 b
2428	2428	1 (3) To negotiate and enter into loan agreements and
2429	2429	2 other agreements with the Illinois Finance Authority.
2430	2430	3 (4) To obtain and employ personnel and hire
2431	2431	4 consultants that are necessary to fulfill the Agency's
2432	2432	5 purposes, and to make expenditures for that purpose within
2433	2433	6 the appropriations for that purpose.
2434	2434	7 (5) To purchase, receive, take by grant, gift, devise,
2435	2435	8 bequest, or otherwise, lease, or otherwise acquire, own,
2436	2436	9 hold, improve, employ, use, and otherwise deal in and
2437	2437	10 with, real or personal property whether tangible or
2438	2438	11 intangible, or any interest therein, within the State.
2439	2439	12 (6) To acquire real or personal property, whether
2440	2440	13 tangible or intangible, including without limitation
2441	2441	14 property rights, interests in property, franchises,
2442	2442	15 obligations, contracts, and debt and equity securities,
2443	2443	16 and to do so by the exercise of the power of eminent domain
2444	2444	17 in accordance with Section 1-21; except that any real
2445	2445	18 property acquired by the exercise of the power of eminent
2446	2446	19 domain must be located within the State.
2447	2447	20 (7) To sell, convey, lease, exchange, transfer,
2448	2448	21 abandon, or otherwise dispose of, or mortgage, pledge, or
2449	2449	22 create a security interest in, any of its assets,
2450	2450	23 properties, or any interest therein, wherever situated.
2451	2451	24 (8) To purchase, take, receive, subscribe for, or
2452	2452	25 otherwise acquire, hold, make a tender offer for, vote,
2453	2453	26 employ, sell, lend, lease, exchange, transfer, or
2454	2454
2455	2455
2456	2456
2457	2457
2458	2458
2459	2459	HB3779 - 68 - LRB104 11172 AAS 21254 b
2460	2460
2461	2461
2462	2462	HB3779- 69 -LRB104 11172 AAS 21254 b HB3779 - 69 - LRB104 11172 AAS 21254 b
2463	2463	HB3779 - 69 - LRB104 11172 AAS 21254 b
2464	2464	1 otherwise dispose of, mortgage, pledge, or grant a
2465	2465	2 security interest in, use, and otherwise deal in and with,
2466	2466	3 bonds and other obligations, shares, or other securities
2467	2467	4 (or interests therein) issued by others, whether engaged
2468	2468	5 in a similar or different business or activity.
2469	2469	6 (9) To make and execute agreements, contracts, and
2470	2470	7 other instruments necessary or convenient in the exercise
2471	2471	8 of the powers and functions of the Agency under this Act,
2472	2472	9 including contracts with any person, including personal
2473	2473	10 service contracts, or with any local government, State
2474	2474	11 agency, or other entity; and all State agencies and all
2475	2475	12 local governments are authorized to enter into and do all
2476	2476	13 things necessary to perform any such agreement, contract,
2477	2477	14 or other instrument with the Agency. No such agreement,
2478	2478	15 contract, or other instrument shall exceed 40 years.
2479	2479	16 (10) To lend money, invest and reinvest its funds in
2480	2480	17 accordance with the Public Funds Investment Act, and take
2481	2481	18 and hold real and personal property as security for the
2482	2482	19 payment of funds loaned or invested.
2483	2483	20 (11) To borrow money at such rate or rates of interest
2484	2484	21 as the Agency may determine, issue its notes, bonds, or
2485	2485	22 other obligations to evidence that indebtedness, and
2486	2486	23 secure any of its obligations by mortgage or pledge of its
2487	2487	24 real or personal property, machinery, equipment,
2488	2488	25 structures, fixtures, inventories, revenues, grants, and
2489	2489	26 other funds as provided or any interest therein, wherever
2490	2490
2491	2491
2492	2492
2493	2493
2494	2494
2495	2495	HB3779 - 69 - LRB104 11172 AAS 21254 b
2496	2496
2497	2497
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2499	2499	HB3779 - 70 - LRB104 11172 AAS 21254 b
2500	2500	1 situated.
2501	2501	2 (12) To enter into agreements with the Illinois
2502	2502	3 Finance Authority to issue bonds whether or not the income
2503	2503	4 therefrom is exempt from federal taxation.
2504	2504	5 (13) To procure insurance against any loss in
2505	2505	6 connection with its properties or operations in such
2506	2506	7 amount or amounts and from such insurers, including the
2507	2507	8 federal government, as it may deem necessary or desirable,
2508	2508	9 and to pay any premiums therefor.
2509	2509	10 (14) To negotiate and enter into agreements with
2510	2510	11 trustees or receivers appointed by United States
2511	2511	12 bankruptcy courts or federal district courts or in other
2512	2512	13 proceedings involving adjustment of debts and authorize
2513	2513	14 proceedings involving adjustment of debts and authorize
2514	2514	15 legal counsel for the Agency to appear in any such
2515	2515	16 proceedings.
2516	2516	17 (15) To file a petition under Chapter 9 of Title 11 of
2517	2517	18 the United States Bankruptcy Code or take other similar
2518	2518	19 action for the adjustment of its debts.
2519	2519	20 (16) To enter into management agreements for the
2520	2520	21 operation of any of the property or facilities owned by
2521	2521	22 the Agency.
2522	2522	23 (17) To enter into an agreement to transfer and to
2523	2523	24 transfer any land, facilities, fixtures, or equipment of
2524	2524	25 the Agency to one or more municipal electric systems,
2525	2525	26 governmental aggregators, or rural electric agencies or
2526	2526
2527	2527
2528	2528
2529	2529
2530	2530
2531	2531	HB3779 - 70 - LRB104 11172 AAS 21254 b
2532	2532
2533	2533
2534	2534	HB3779- 71 -LRB104 11172 AAS 21254 b HB3779 - 71 - LRB104 11172 AAS 21254 b
2535	2535	HB3779 - 71 - LRB104 11172 AAS 21254 b
2536	2536	1 cooperatives, for such consideration and upon such terms
2537	2537	2 as the Agency may determine to be in the best interest of
2538	2538	3 the residents of Illinois.
2539	2539	4 (18) To enter upon any lands and within any building
2540	2540	5 whenever in its judgment it may be necessary for the
2541	2541	6 purpose of making surveys and examinations to accomplish
2542	2542	7 any purpose authorized by this Act.
2543	2543	8 (19) To maintain an office or offices at such place or
2544	2544	9 places in the State as it may determine.
2545	2545	10 (20) To request information, and to make any inquiry,
2546	2546	11 investigation, survey, or study that the Agency may deem
2547	2547	12 necessary to enable it effectively to carry out the
2548	2548	13 provisions of this Act.
2549	2549	14 (21) To accept and expend appropriations.
2550	2550	15 (22) To engage in any activity or operation that is
2551	2551	16 incidental to and in furtherance of efficient operation to
2552	2552	17 accomplish the Agency's purposes, including hiring
2553	2553	18 employees that the Director deems essential for the
2554	2554	19 operations of the Agency.
2555	2555	20 (23) To adopt, revise, amend, and repeal rules with
2556	2556	21 respect to its operations, properties, and facilities as
2557	2557	22 may be necessary or convenient to carry out the purposes
2558	2558	23 of this Act, subject to the provisions of the Illinois
2559	2559	24 Administrative Procedure Act and Sections 1-22 and 1-35 of
2560	2560	25 this Act.
2561	2561	26 (24) To establish and collect charges and fees as
2562	2562
2563	2563
2564	2564
2565	2565
2566	2566
2567	2567	HB3779 - 71 - LRB104 11172 AAS 21254 b
2568	2568
2569	2569
2570	2570	HB3779- 72 -LRB104 11172 AAS 21254 b HB3779 - 72 - LRB104 11172 AAS 21254 b
2571	2571	HB3779 - 72 - LRB104 11172 AAS 21254 b
2572	2572	1 described in this Act.
2573	2573	2 (25) To conduct competitive gasification feedstock
2574	2574	3 procurement processes to procure the feedstocks for the
2575	2575	4 clean coal SNG brownfield facility in accordance with the
2576	2576	5 requirements of Section 1-78 of this Act.
2577	2577	6 (26) To review, revise, and approve sourcing
2578	2578	7 agreements and mediate and resolve disputes between gas
2579	2579	8 utilities and the clean coal SNG brownfield facility
2580	2580	9 pursuant to subsection (h-1) of Section 9-220 of the
2581	2581	10 Public Utilities Act.
2582	2582	11 (27) To request, review and accept proposals, execute
2583	2583	12 contracts, purchase renewable energy credits and otherwise
2584	2584	13 dedicate funds from the Illinois Power Agency Renewable
2585	2585	14 Energy Resources Fund to create and carry out the
2586	2586	15 objectives of the Illinois Solar for All Program in
2587	2587	16 accordance with Section 1-56 of this Act.
2588	2588	17 (28) To ensure Illinois residents and business benefit
2589	2589	18 from programs administered by the Agency and are properly
2590	2590	19 protected from any deceptive or misleading marketing
2591	2591	20 practices by participants in the Agency's programs and
2592	2592	21 procurements.
2593	2593	22 (c) In conducting the procurement of electricity or other
2594	2594	23 products, beginning January 1, 2022, the Agency shall not
2595	2595	24 procure any products or services from persons or organizations
2596	2596	25 that are in violation of the Displaced Energy Workers Bill of
2597	2597	26 Rights, as provided under the Energy Community Reinvestment
2598	2598
2599	2599
2600	2600
2601	2601
2602	2602
2603	2603	HB3779 - 72 - LRB104 11172 AAS 21254 b
2604	2604
2605	2605
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2607	2607	HB3779 - 73 - LRB104 11172 AAS 21254 b
2608	2608	1 Act at the time of the procurement event or fail to comply the
2609	2609	2 labor standards established in subparagraph (Q) of paragraph
2610	2610	3 (1) of subsection (c) of Section 1-75.
2611	2611	4 (Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)
2612	2612	5 (20 ILCS 3855/1-56)
2613	2613	6 Sec. 1-56. Illinois Power Agency Renewable Energy
2614	2614	7 Resources Fund; Illinois Solar for All Program.
2615	2615	8 (a) The Illinois Power Agency Renewable Energy Resources
2616	2616	9 Fund is created as a special fund in the State treasury.
2617	2617	10 (b) The Illinois Power Agency Renewable Energy Resources
2618	2618	11 Fund shall be administered by the Agency as described in this
2619	2619	12 subsection (b), provided that the changes to this subsection
2620	2620	13 (b) made by Public Act 99-906 shall not interfere with
2621	2621	14 existing contracts under this Section.
2622	2622	15 (1) The Illinois Power Agency Renewable Energy
2623	2623	16 Resources Fund shall be used to purchase renewable energy
2624	2624	17 credits or fund rebates according to any approved
2625	2625	18 procurement plan developed by the Agency prior to June 1,
2626	2626	19 2017.
2627	2627	20 (2) The Illinois Power Agency Renewable Energy
2628	2628	21 Resources Fund shall also be used to create the Illinois
2629	2629	22 Solar for All Program, which provides incentives for
2630	2630	23 low-income distributed generation and community solar
2631	2631	24 projects, and other associated approved expenditures. The
2632	2632	25 objectives of the Illinois Solar for All Program are to
2633	2633
2634	2634
2635	2635
2636	2636
2637	2637
2638	2638	HB3779 - 73 - LRB104 11172 AAS 21254 b
2639	2639
2640	2640
2641	2641	HB3779- 74 -LRB104 11172 AAS 21254 b HB3779 - 74 - LRB104 11172 AAS 21254 b
2642	2642	HB3779 - 74 - LRB104 11172 AAS 21254 b
2643	2643	1 bring photovoltaics to low-income communities in this
2644	2644	2 State in a manner that maximizes the development of new
2645	2645	3 photovoltaic generating facilities, to create a long-term,
2646	2646	4 low-income solar marketplace throughout this State, to
2647	2647	5 integrate, through interaction with stakeholders, with
2648	2648	6 existing energy efficiency initiatives, and to minimize
2649	2649	7 administrative costs. The Illinois Solar for All Program
2650	2650	8 shall be implemented in a manner that seeks to minimize
2651	2651	9 administrative costs, and maximize efficiencies and
2652	2652	10 synergies available through coordination with similar
2653	2653	11 initiatives, including the Adjustable Block program
2654	2654	12 described in subparagraphs (K) through (M) of paragraph
2655	2655	13 (1) of subsection (c) of Section 1-75, energy efficiency
2656	2656	14 programs, job training programs, and community action
2657	2657	15 agencies. The Agency shall strive to ensure that projects
2658	2658	16 incentivized renewable energy credits procured through the
2659	2659	17 Illinois Solar for All Program and each of its subprograms
2660	2660	18 are purchased from projects across the breadth of
2661	2661	19 low-income and environmental justice communities in
2662	2662	20 Illinois, including both urban and rural communities, are
2663	2663	21 not concentrated in a few communities, and do not exclude
2664	2664	22 particular low-income or environmental justice
2665	2665	23 communities. The Agency shall include a description of its
2666	2666	24 proposed approach to the design, administration,
2667	2667	25 implementation and evaluation of the Illinois Solar for
2668	2668	26 All Program, as part of the long-term renewable resources
2669	2669
2670	2670
2671	2671
2672	2672
2673	2673
2674	2674	HB3779 - 74 - LRB104 11172 AAS 21254 b
2675	2675
2676	2676
2677	2677	HB3779- 75 -LRB104 11172 AAS 21254 b HB3779 - 75 - LRB104 11172 AAS 21254 b
2678	2678	HB3779 - 75 - LRB104 11172 AAS 21254 b
2679	2679	1 procurement plan authorized by subsection (c) of Section
2680	2680	2 1-75 of this Act, and the program shall be designed to grow
2681	2681	3 the low-income solar market. The Agency or utility, as
2682	2682	4 applicable, shall purchase renewable energy credits or
2683	2683	5 equivalent amount in the form of an upfront rebate from
2684	2684	6 the (i) photovoltaic distributed renewable energy
2685	2685	7 generation projects and (ii) community solar projects that
2686	2686	8 are procured under procurement processes authorized by the
2687	2687	9 long-term renewable resources procurement plans approved
2688	2688	10 by the Commission.
2689	2689	11 The Illinois Solar for All Program shall include the
2690	2690	12 program offerings described in subparagraphs (A) through
2691	2691	13 (E) of this paragraph (2), which the Agency shall
2692	2692	14 implement through contracts with third-party providers
2693	2693	15 and, subject to appropriation, pay the approximate amounts
2694	2694	16 identified using monies available in the Illinois Power
2695	2695	17 Agency Renewable Energy Resources Fund. Each contract that
2696	2696	18 provides for the installation of solar facilities shall
2697	2697	19 provide that the solar facilities will produce energy and
2698	2698	20 economic benefits, at a level determined by the Agency to
2699	2699	21 be reasonable, for the participating low-income customers.
2700	2700	22 The monies available in the Illinois Power Agency
2701	2701	23 Renewable Energy Resources Fund and not otherwise
2702	2702	24 committed to contracts executed under subsection (i) of
2703	2703	25 this Section, as well as, in the case of the programs
2704	2704	26 described under subparagraphs (A) through (E) of this
2705	2705
2706	2706
2707	2707
2708	2708
2709	2709
2710	2710	HB3779 - 75 - LRB104 11172 AAS 21254 b
2711	2711
2712	2712
2713	2713	HB3779- 76 -LRB104 11172 AAS 21254 b HB3779 - 76 - LRB104 11172 AAS 21254 b
2714	2714	HB3779 - 76 - LRB104 11172 AAS 21254 b
2715	2715	1 paragraph (2), funding authorized pursuant to subparagraph
2716	2716	2 (O) of paragraph (1) of subsection (c) of Section 1-75 of
2717	2717	3 this Act, shall initially be allocated among the programs
2718	2718	4 described in this paragraph (2), as follows: 35% of these
2719	2719	5 funds shall be allocated to programs described in
2720	2720	6 subparagraphs (A) and (E) of this paragraph (2), 40% of
2721	2721	7 these funds shall be allocated to programs described in
2722	2722	8 subparagraph (B) of this paragraph (2), and 25% of these
2723	2723	9 funds shall be allocated to programs described in
2724	2724	10 subparagraph (C) of this paragraph (2). The allocation of
2725	2725	11 funds among subparagraphs (A), (B), (C), and (E) of this
2726	2726	12 paragraph (2) may be changed if the Agency, after
2727	2727	13 receiving input through a stakeholder process, determines
2728	2728	14 incentives in subparagraphs (A), (B), (C), or (E) of this
2729	2729	15 paragraph (2) have not been adequately subscribed to fully
2730	2730	16 utilize available Illinois Solar for All Program funds.
2731	2731	17 Contracts that will be paid with funds in the Illinois
2732	2732	18 Power Agency Renewable Energy Resources Fund shall be
2733	2733	19 executed by the Agency. Contracts that will be paid with
2734	2734	20 funds collected by an electric utility shall be executed
2735	2735	21 by the electric utility.
2736	2736	22 Contracts under the Illinois Solar for All Program
2737	2737	23 shall include an approach, as set forth in the long-term
2738	2738	24 renewable resources procurement plans, to ensure the
2739	2739	25 wholesale market value of the energy is credited to
2740	2740	26 participating low-income customers or organizations and to
2741	2741
2742	2742
2743	2743
2744	2744
2745	2745
2746	2746	HB3779 - 76 - LRB104 11172 AAS 21254 b
2747	2747
2748	2748
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2750	2750	HB3779 - 77 - LRB104 11172 AAS 21254 b
2751	2751	1 ensure tangible economic benefits flow directly to program
2752	2752	2 participants, except in the case of low-income
2753	2753	3 multi-family housing where the low-income customer does
2754	2754	4 not directly pay for energy. Priority shall be given to
2755	2755	5 projects that demonstrate meaningful involvement of
2756	2756	6 low-income community members in designing the initial
2757	2757	7 proposals. Acceptable proposals to implement projects must
2758	2758	8 demonstrate the applicant's ability to conduct initial
2759	2759	9 community outreach, education, and recruitment of
2760	2760	10 low-income participants in the community. Projects must
2761	2761	11 include job training opportunities if available, with the
2762	2762	12 specific level of trainee usage to be determined through
2763	2763	13 the Agency's long-term renewable resources procurement
2764	2764	14 plan, and the Illinois Solar for All Program Administrator
2765	2765	15 shall coordinate with the job training programs described
2766	2766	16 in paragraph (1) of subsection (a) of Section 16-108.12 of
2767	2767	17 the Public Utilities Act and in the Energy Transition Act.
2768	2768	18 The Agency shall make every effort to ensure that
2769	2769	19 small and emerging businesses, particularly those located
2770	2770	20 in low-income and environmental justice communities, are
2771	2771	21 able to participate in the Illinois Solar for All Program.
2772	2772	22 These efforts may include, but shall not be limited to,
2773	2773	23 proactive support from the program administrator,
2774	2774	24 different or preferred access to subprograms and
2775	2775	25 administrator-identified customers or grassroots
2776	2776	26 education provider-identified customers, and different
2777	2777
2778	2778
2779	2779
2780	2780
2781	2781
2782	2782	HB3779 - 77 - LRB104 11172 AAS 21254 b
2783	2783
2784	2784
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2786	2786	HB3779 - 78 - LRB104 11172 AAS 21254 b
2787	2787	1 incentive levels. The Agency shall report on progress and
2788	2788	2 barriers to participation of small and emerging businesses
2789	2789	3 in the Illinois Solar for All Program at least once a year.
2790	2790	4 The report shall be made available on the Agency's website
2791	2791	5 and, in years when the Agency is updating its long-term
2792	2792	6 renewable resources procurement plan, included in that
2793	2793	7 Plan.
2794	2794	8 (A) Low-income single-family and small multifamily
2795	2795	9 solar incentive. This program will provide incentives
2796	2796	10 to low-income customers, either directly or through
2797	2797	11 solar providers, to increase the participation of
2798	2798	12 low-income households in photovoltaic on-site
2799	2799	13 distributed generation at residential buildings
2800	2800	14 containing one to 4 units. Companies participating in
2801	2801	15 this program that install solar panels shall commit to
2802	2802	16 hiring job trainees for a portion of their low-income
2803	2803	17 installations, and an administrator shall facilitate
2804	2804	18 partnering the companies that install solar panels
2805	2805	19 with entities that provide solar panel installation
2806	2806	20 job training. It is a goal of this program that a
2807	2807	21 minimum of 25% of the incentives for this program be
2808	2808	22 allocated to projects located within environmental
2809	2809	23 justice communities. Contracts entered into under this
2810	2810	24 paragraph may be entered into with an entity that will
2811	2811	25 develop and administer the program and shall also
2812	2812	26 include contracts for renewable energy credits from
2813	2813
2814	2814
2815	2815
2816	2816
2817	2817
2818	2818	HB3779 - 78 - LRB104 11172 AAS 21254 b
2819	2819
2820	2820
2821	2821	HB3779- 79 -LRB104 11172 AAS 21254 b HB3779 - 79 - LRB104 11172 AAS 21254 b
2822	2822	HB3779 - 79 - LRB104 11172 AAS 21254 b
2823	2823	1 the photovoltaic distributed generation or an
2824	2824	2 equivalent amount as an upfront rebate that is the
2825	2825	3 subject of the program, as set forth in the long-term
2826	2826	4 renewable resources procurement plan. Additionally:
2827	2827	5 (i) The Agency shall reserve a portion of this
2828	2828	6 program for projects that promote energy
2829	2829	7 sovereignty through ownership of projects by
2830	2830	8 low-income households, not-for-profit
2831	2831	9 organizations providing services to low-income
2832	2832	10 households, affordable housing owners, community
2833	2833	11 cooperatives, or community-based limited liability
2834	2834	12 companies providing services to low-income
2835	2835	13 households. Projects that feature energy ownership
2836	2836	14 should ensure that local people have control of
2837	2837	15 the project and reap benefits from the project
2838	2838	16 over and above energy bill savings. The Agency may
2839	2839	17 consider the inclusion of projects that promote
2840	2840	18 ownership over time or that involve partial
2841	2841	19 project ownership by communities, as promoting
2842	2842	20 energy sovereignty. Incentives for projects that
2843	2843	21 promote energy sovereignty may be higher than
2844	2844	22 incentives for equivalent projects that do not
2845	2845	23 promote energy sovereignty under this same
2846	2846	24 program.
2847	2847	25 (ii) Through its long-term renewable resources
2848	2848	26 procurement plan, the Agency shall consider
2849	2849
2850	2850
2851	2851
2852	2852
2853	2853
2854	2854	HB3779 - 79 - LRB104 11172 AAS 21254 b
2855	2855
2856	2856
2857	2857	HB3779- 80 -LRB104 11172 AAS 21254 b HB3779 - 80 - LRB104 11172 AAS 21254 b
2858	2858	HB3779 - 80 - LRB104 11172 AAS 21254 b
2859	2859	1 additional program and contract requirements to
2860	2860	2 ensure faithful compliance by applicants
2861	2861	3 benefiting from preferences for projects
2862	2862	4 designated to promote energy sovereignty. The
2863	2863	5 Agency shall make every effort to enable solar
2864	2864	6 providers already participating in the Adjustable
2865	2865	7 Block Program under subparagraph (K) of paragraph
2866	2866	8 (1) of subsection (c) of Section 1-75 of this Act,
2867	2867	9 and particularly solar providers developing
2868	2868	10 projects under item (i) of subparagraph (K) of
2869	2869	11 paragraph (1) of subsection (c) of Section 1-75 of
2870	2870	12 this Act to easily participate in the Low-Income
2871	2871	13 Distributed Generation Incentive program described
2872	2872	14 under this subparagraph (A), and vice versa. This
2873	2873	15 effort may include, but shall not be limited to,
2874	2874	16 utilizing similar or the same application systems
2875	2875	17 and processes, similar or the same forms and
2876	2876	18 formats of communication, and providing active
2877	2877	19 outreach to companies participating in one program
2878	2878	20 but not the other. The Agency shall report on
2879	2879	21 efforts made to encourage this cross-participation
2880	2880	22 in its long-term renewable resources procurement
2881	2881	23 plan.
2882	2882	24 (B) Low-Income Community Solar Project Initiative.
2883	2883	25 Incentives shall be offered to low-income customers,
2884	2884	26 either directly or through developers, to increase the
2885	2885
2886	2886
2887	2887
2888	2888
2889	2889
2890	2890	HB3779 - 80 - LRB104 11172 AAS 21254 b
2891	2891
2892	2892
2893	2893	HB3779- 81 -LRB104 11172 AAS 21254 b HB3779 - 81 - LRB104 11172 AAS 21254 b
2894	2894	HB3779 - 81 - LRB104 11172 AAS 21254 b
2895	2895	1 participation of low-income subscribers of community
2896	2896	2 solar projects. The developer of each project shall
2897	2897	3 identify its partnership with community stakeholders
2898	2898	4 regarding the location, development, and participation
2899	2899	5 in the project, provided that nothing shall preclude a
2900	2900	6 project from including an anchor tenant that does not
2901	2901	7 qualify as low-income. Companies participating in this
2902	2902	8 program that develop or install solar projects shall
2903	2903	9 commit to hiring job trainees for a portion of their
2904	2904	10 low-income installations, and an administrator shall
2905	2905	11 facilitate partnering the companies that install solar
2906	2906	12 projects with entities that provide solar installation
2907	2907	13 and related job training. It is a goal of this program
2908	2908	14 that a minimum of 25% of the incentives for this
2909	2909	15 program be allocated to community photovoltaic
2910	2910	16 projects in environmental justice communities. The
2911	2911	17 Agency shall reserve a portion of this program for
2912	2912	18 projects that promote energy sovereignty through
2913	2913	19 ownership of projects by low-income households,
2914	2914	20 not-for-profit organizations providing services to
2915	2915	21 low-income households, affordable housing owners, or
2916	2916	22 community-based limited liability companies providing
2917	2917	23 services to low-income households. Projects that
2918	2918	24 feature energy ownership should ensure that local
2919	2919	25 people have control of the project and reap benefits
2920	2920	26 from the project over and above energy bill savings.
2921	2921
2922	2922
2923	2923
2924	2924
2925	2925
2926	2926	HB3779 - 81 - LRB104 11172 AAS 21254 b
2927	2927
2928	2928
2929	2929	HB3779- 82 -LRB104 11172 AAS 21254 b HB3779 - 82 - LRB104 11172 AAS 21254 b
2930	2930	HB3779 - 82 - LRB104 11172 AAS 21254 b
2931	2931	1 The Agency may consider the inclusion of projects that
2932	2932	2 promote ownership over time or that involve partial
2933	2933	3 project ownership by communities, as promoting energy
2934	2934	4 sovereignty. Incentives for projects that promote
2935	2935	5 energy sovereignty may be higher than incentives for
2936	2936	6 equivalent projects that do not promote energy
2937	2937	7 sovereignty under this same program. Contracts entered
2938	2938	8 into under this paragraph may be entered into with
2939	2939	9 developers and shall also include contracts for
2940	2940	10 renewable energy credits related to the program.
2941	2941	11 (C) Incentives for non-profits and public
2942	2942	12 facilities. Under this program funds shall be used to
2943	2943	13 support on-site photovoltaic distributed renewable
2944	2944	14 energy generation devices to serve the load associated
2945	2945	15 with not-for-profit customers and to support
2946	2946	16 photovoltaic distributed renewable energy generation
2947	2947	17 that uses photovoltaic technology to serve the load
2948	2948	18 associated with public sector customers taking service
2949	2949	19 at public buildings. Companies participating in this
2950	2950	20 program that develop or install solar projects shall
2951	2951	21 commit to hiring job trainees for a portion of their
2952	2952	22 low-income installations, and an administrator shall
2953	2953	23 facilitate partnering the companies that install solar
2954	2954	24 projects with entities that provide solar installation
2955	2955	25 and related job training. Through its long-term
2956	2956	26 renewable resources procurement plan, the Agency shall
2957	2957
2958	2958
2959	2959
2960	2960
2961	2961
2962	2962	HB3779 - 82 - LRB104 11172 AAS 21254 b
2963	2963
2964	2964
2965	2965	HB3779- 83 -LRB104 11172 AAS 21254 b HB3779 - 83 - LRB104 11172 AAS 21254 b
2966	2966	HB3779 - 83 - LRB104 11172 AAS 21254 b
2967	2967	1 consider additional program and contract requirements
2968	2968	2 to ensure faithful compliance by applicants benefiting
2969	2969	3 from preferences for projects designated to promote
2970	2970	4 energy sovereignty. It is a goal of this program that
2971	2971	5 at least 25% of the incentives for this program be
2972	2972	6 allocated to projects located in environmental justice
2973	2973	7 communities. Contracts entered into under this
2974	2974	8 paragraph may be entered into with an entity that will
2975	2975	9 develop and administer the program or with developers
2976	2976	10 and shall also include contracts for renewable energy
2977	2977	11 credits or upfront rebates related to the program.
2978	2978	12 (D) (Blank).
2979	2979	13 (E) Low-income large multifamily solar incentive.
2980	2980	14 This program shall provide incentives to low-income
2981	2981	15 customers, either directly or through solar providers,
2982	2982	16 to increase the participation of low-income households
2983	2983	17 in photovoltaic on-site distributed generation at
2984	2984	18 residential buildings with 5 or more units. Companies
2985	2985	19 participating in this program that develop or install
2986	2986	20 solar projects shall commit to hiring job trainees for
2987	2987	21 a portion of their low-income installations, and an
2988	2988	22 administrator shall facilitate partnering the
2989	2989	23 companies that install solar projects with entities
2990	2990	24 that provide solar installation and related job
2991	2991	25 training. It is a goal of this program that a minimum
2992	2992	26 of 25% of the incentives for this program be allocated
2993	2993
2994	2994
2995	2995
2996	2996
2997	2997
2998	2998	HB3779 - 83 - LRB104 11172 AAS 21254 b
2999	2999
3000	3000
3001	3001	HB3779- 84 -LRB104 11172 AAS 21254 b HB3779 - 84 - LRB104 11172 AAS 21254 b
3002	3002	HB3779 - 84 - LRB104 11172 AAS 21254 b
3003	3003	1 to projects located within environmental justice
3004	3004	2 communities. The Agency shall reserve a portion of
3005	3005	3 this program for projects that promote energy
3006	3006	4 sovereignty through ownership of projects by
3007	3007	5 low-income households, not-for-profit organizations
3008	3008	6 providing services to low-income households,
3009	3009	7 affordable housing owners, or community-based limited
3010	3010	8 liability companies providing services to low-income
3011	3011	9 households. Projects that feature energy ownership
3012	3012	10 should ensure that local people have control of the
3013	3013	11 project and reap benefits from the project over and
3014	3014	12 above energy bill savings. The Agency may consider the
3015	3015	13 inclusion of projects that promote ownership over time
3016	3016	14 or that involve partial project ownership by
3017	3017	15 communities, as promoting energy sovereignty.
3018	3018	16 Incentives for projects that promote energy
3019	3019	17 sovereignty may be higher than incentives for
3020	3020	18 equivalent projects that do not promote energy
3021	3021	19 sovereignty under this same program.
3022	3022	20 The requirement that a qualified person, as defined in
3023	3023	21 paragraph (1) of subsection (i) of this Section, install
3024	3024	22 photovoltaic devices does not apply to the Illinois Solar
3025	3025	23 for All Program described in this subsection (b).
3026	3026	24 In addition to the programs outlined in paragraphs (A)
3027	3027	25 through (E), the Agency and other parties may propose
3028	3028	26 additional programs through the Long-Term Renewable
3029	3029
3030	3030
3031	3031
3032	3032
3033	3033
3034	3034	HB3779 - 84 - LRB104 11172 AAS 21254 b
3035	3035
3036	3036
3037	3037	HB3779- 85 -LRB104 11172 AAS 21254 b HB3779 - 85 - LRB104 11172 AAS 21254 b
3038	3038	HB3779 - 85 - LRB104 11172 AAS 21254 b
3039	3039	1 Resources Procurement Plan developed and approved under
3040	3040	2 paragraph (5) of subsection (b) of Section 16-111.5 of the
3041	3041	3 Public Utilities Act. Additional programs may target
3042	3042	4 market segments not specified above and may also include
3043	3043	5 incentives targeted to increase the uptake of
3044	3044	6 nonphotovoltaic technologies by low-income customers,
3045	3045	7 including energy storage paired with photovoltaics, if the
3046	3046	8 Commission determines that the Illinois Solar for All
3047	3047	9 Program would provide greater benefits to the public
3048	3048	10 health and well-being of low-income residents through also
3049	3049	11 supporting that additional program versus supporting
3050	3050	12 programs already authorized.
3051	3051	13 (3) Costs associated with the Illinois Solar for All
3052	3052	14 Program and its components described in paragraph (2) of
3053	3053	15 this subsection (b), including, but not limited to, costs
3054	3054	16 associated with procuring experts, consultants, and the
3055	3055	17 program administrator referenced in this subsection (b)
3056	3056	18 and related incremental costs, costs related to income
3057	3057	19 verification and facilitating customer participation in
3058	3058	20 the program, and costs related to the evaluation of the
3059	3059	21 Illinois Solar for All Program, may be paid for using
3060	3060	22 monies in the Illinois Power Agency Renewable Energy
3061	3061	23 Resources Fund, and funds allocated pursuant to
3062	3062	24 subparagraph (O) of paragraph (1) of subsection (c) of
3063	3063	25 Section 1-75, but the Agency or program administrator
3064	3064	26 shall strive to minimize costs in the implementation of
3065	3065
3066	3066
3067	3067
3068	3068
3069	3069
3070	3070	HB3779 - 85 - LRB104 11172 AAS 21254 b
3071	3071
3072	3072
3073	3073	HB3779- 86 -LRB104 11172 AAS 21254 b HB3779 - 86 - LRB104 11172 AAS 21254 b
3074	3074	HB3779 - 86 - LRB104 11172 AAS 21254 b
3075	3075	1 the program. The Agency or contracting electric utility
3076	3076	2 shall purchase renewable energy credits or fund upfront
3077	3077	3 rebates from generation that is the subject of a contract
3078	3078	4 under subparagraphs (A) through (E) of paragraph (2) of
3079	3079	5 this subsection (b), and may pay for such renewable energy
3080	3080	6 credits or rebates through an upfront payment per
3081	3081	7 installed kilowatt of nameplate capacity paid once the
3082	3082	8 device is interconnected at the distribution system level
3083	3083	9 of the interconnecting utility and verified as energized.
3084	3084	10 The IPA shall determine in its long-term renewable
3085	3085	11 resources procurement plan described in subsection (c) of
3086	3086	12 Section 1-75 of this Act and Section 16-111.5 of the
3087	3087	13 Public Utilities Act if renewable energy credits or an
3088	3088	14 upfront rebate directly to consumers is most effective at
3089	3089	15 achieving the aims of the Illinois Solar for All program
3090	3090	16 with the most efficient use of funds. If the Agency
3091	3091	17 chooses to continue with renewable energy credits,
3092	3092	18 payments Payments for renewable energy credits shall be in
3093	3093	19 exchange for all renewable energy credits generated by the
3094	3094	20 system during the first 15 years of operation and shall be
3095	3095	21 structured to overcome barriers to participation in the
3096	3096	22 solar market by the low-income community. The incentives
3097	3097	23 provided for in this Section may be implemented through
3098	3098	24 the pricing of renewable energy credits where the prices
3099	3099	25 paid for the credits are higher than the prices from
3100	3100	26 programs offered under subsection (c) of Section 1-75 of
3101	3101
3102	3102
3103	3103
3104	3104
3105	3105
3106	3106	HB3779 - 86 - LRB104 11172 AAS 21254 b
3107	3107
3108	3108
3109	3109	HB3779- 87 -LRB104 11172 AAS 21254 b HB3779 - 87 - LRB104 11172 AAS 21254 b
3110	3110	HB3779 - 87 - LRB104 11172 AAS 21254 b
3111	3111	1 this Act to account for the additional capital necessary
3112	3112	2 to successfully access targeted market segments. The
3113	3113	3 Agency or contracting electric utility shall retire or
3114	3114	4 track any renewable energy credits purchased under this
3115	3115	5 program and the credits shall count toward the obligation
3116	3116	6 under subsection (c) of Section 1-75 of this Act for the
3117	3117	7 electric utility to which the project is interconnected,
3118	3118	8 if applicable.
3119	3119	9 The Agency shall direct that up to 5% of the funds
3120	3120	10 available under the Illinois Solar for All Program to
3121	3121	11 community-based groups and other qualifying organizations
3122	3122	12 to assist in community-driven education efforts related to
3123	3123	13 the Illinois Solar for All Program, including general
3124	3124	14 energy education, job training program outreach efforts,
3125	3125	15 and other activities deemed to be qualified by the Agency.
3126	3126	16 Grassroots education funding shall not be used to support
3127	3127	17 the marketing by solar project development firms and
3128	3128	18 organizations, unless such education provides equal
3129	3129	19 opportunities for all applicable firms and organizations.
3130	3130	20 The Agency shall direct up to 25% of the funds
3131	3131	21 currently allocated to subparagraphs (A), (C), and (E) of
3132	3132	22 this subsection (b) towards grants, rebates, or incentives
3133	3133	23 designed to incentivize energy storage paired with
3134	3134	24 photovoltaic distributed renewable energy generation
3135	3135	25 devices. This new incentive program for income-qualified
3136	3136	26 storage may be titled "Illinois Storage for All". The
3137	3137
3138	3138
3139	3139
3140	3140
3141	3141
3142	3142	HB3779 - 87 - LRB104 11172 AAS 21254 b
3143	3143
3144	3144
3145	3145	HB3779- 88 -LRB104 11172 AAS 21254 b HB3779 - 88 - LRB104 11172 AAS 21254 b
3146	3146	HB3779 - 88 - LRB104 11172 AAS 21254 b
3147	3147	1 Illinois Storage for All program shall be available to
3148	3148	2 current and future participants of the Low-income single
3149	3149	3 family and small multifamily subprogram described in
3150	3150	4 subparagraph (A), the subprogram for non-profit and public
3151	3151	5 facilities described in subparagraph (C), and the
3152	3152	6 Low-income large multifamily solar incentive described in
3153	3153	7 subparagraph (E) of paragraph (2). The program shall be
3154	3154	8 designed to support community energy resilience, disaster
3155	3155	9 preparedness, and energy bill reductions, particularly for
3156	3156	10 residents of low-income and environmental justice
3157	3157	11 communities. The Agency shall propose the funding amount,
3158	3158	12 structure, and details of this storage incentive program
3159	3159	13 in their long-term renewable resources procurement plan
3160	3160	14 described in subsection (c) of Section 1-75 of this Act
3161	3161	15 and Section 16-111.5 of the Public Utilities Act. Prior to
3162	3162	16 filing the proposed program in their long-term renewable
3163	3163	17 resources procurement plan, the Agency shall separately
3164	3164	18 engage stakeholders in program design including, but not
3165	3165	19 limited to, members of the Illinois Commission on
3166	3166	20 Environmental Justice described in Section 10 of the
3167	3167	21 Environmental Justice Act, representatives of Approved
3168	3168	22 Vendors participating in the Illinois Solar for All
3169	3169	23 Program, representatives of community-based
3170	3170	24 organizations, and members of the Illinois Solar for All
3171	3171	25 Stakeholder Advisory Group.
3172	3172	26 (4) The Agency shall, consistent with the requirements
3173	3173
3174	3174
3175	3175
3176	3176
3177	3177
3178	3178	HB3779 - 88 - LRB104 11172 AAS 21254 b
3179	3179
3180	3180
3181	3181	HB3779- 89 -LRB104 11172 AAS 21254 b HB3779 - 89 - LRB104 11172 AAS 21254 b
3182	3182	HB3779 - 89 - LRB104 11172 AAS 21254 b
3183	3183	1 of this subsection (b), propose the Illinois Solar for All
3184	3184	2 Program terms, conditions, and requirements, including the
3185	3185	3 prices to be paid for renewable energy credits or rebates,
3186	3186	4 and which prices may be determined through a formula,
3187	3187	5 through the development, review, and approval of the
3188	3188	6 Agency's long-term renewable resources procurement plan
3189	3189	7 described in subsection (c) of Section 1-75 of this Act
3190	3190	8 and Section 16-111.5 of the Public Utilities Act. In the
3191	3191	9 course of the Commission proceeding initiated to review
3192	3192	10 and approve the plan, including the Illinois Solar for All
3193	3193	11 Program proposed by the Agency, a party may propose an
3194	3194	12 additional low-income solar or solar incentive program, or
3195	3195	13 modifications to the programs proposed by the Agency, and
3196	3196	14 the Commission may approve an additional program, or
3197	3197	15 modifications to the Agency's proposed program, if the
3198	3198	16 additional or modified program more effectively maximizes
3199	3199	17 the benefits to low-income customers after taking into
3200	3200	18 account all relevant factors, including, but not limited
3201	3201	19 to, the extent to which a competitive market for
3202	3202	20 low-income solar has developed. Following the Commission's
3203	3203	21 approval of the Illinois Solar for All Program, the Agency
3204	3204	22 or a party may propose adjustments to the program terms,
3205	3205	23 conditions, and requirements, including the price offered
3206	3206	24 to new systems, to ensure the long-term viability and
3207	3207	25 success of the program. The Commission shall review and
3208	3208	26 approve any modifications to the program through the plan
3209	3209
3210	3210
3211	3211
3212	3212
3213	3213
3214	3214	HB3779 - 89 - LRB104 11172 AAS 21254 b
3215	3215
3216	3216
3217	3217	HB3779- 90 -LRB104 11172 AAS 21254 b HB3779 - 90 - LRB104 11172 AAS 21254 b
3218	3218	HB3779 - 90 - LRB104 11172 AAS 21254 b
3219	3219	1 revision process described in Section 16-111.5 of the
3220	3220	2 Public Utilities Act.
3221	3221	3 (5) The Agency shall issue a request for
3222	3222	4 qualifications for a third-party program administrator or
3223	3223	5 administrators to administer all or a portion of the
3224	3224	6 Illinois Solar for All Program. The third-party program
3225	3225	7 administrator shall be chosen through a competitive bid
3226	3226	8 process based on selection criteria and requirements
3227	3227	9 developed by the Agency, including, but not limited to,
3228	3228	10 experience in administering low-income energy programs and
3229	3229	11 overseeing statewide clean energy or energy efficiency
3230	3230	12 services. If the Agency retains a program administrator or
3231	3231	13 administrators to implement all or a portion of the
3232	3232	14 Illinois Solar for All Program, each administrator shall
3233	3233	15 periodically submit reports to the Agency and Commission
3234	3234	16 for each program that it administers, at appropriate
3235	3235	17 intervals to be identified by the Agency in its long-term
3236	3236	18 renewable resources procurement plan, provided that the
3237	3237	19 reporting interval is at least quarterly. The third-party
3238	3238	20 program administrator may be, but need not be, the same
3239	3239	21 administrator as for the Adjustable Block program
3240	3240	22 described in subparagraphs (K) through (M) of paragraph
3241	3241	23 (1) of subsection (c) of Section 1-75. The Agency, through
3242	3242	24 its long-term renewable resources procurement plan
3243	3243	25 approval process, shall also determine if individual
3244	3244	26 subprograms of the Illinois Solar for All Program are
3245	3245
3246	3246
3247	3247
3248	3248
3249	3249
3250	3250	HB3779 - 90 - LRB104 11172 AAS 21254 b
3251	3251
3252	3252
3253	3253	HB3779- 91 -LRB104 11172 AAS 21254 b HB3779 - 91 - LRB104 11172 AAS 21254 b
3254	3254	HB3779 - 91 - LRB104 11172 AAS 21254 b
3255	3255	1 better served by a different or separate Program
3256	3256	2 Administrator.
3257	3257	3 The third-party administrator's responsibilities
3258	3258	4 shall also include facilitating placement for graduates of
3259	3259	5 Illinois-based renewable energy-specific job training
3260	3260	6 programs, including the Clean Jobs Workforce Network
3261	3261	7 Program and the Illinois Climate Works Preapprenticeship
3262	3262	8 Program administered by the Department of Commerce and
3263	3263	9 Economic Opportunity and programs administered under
3264	3264	10 Section 16-108.12 of the Public Utilities Act. To increase
3265	3265	11 the uptake of trainees by participating firms, the
3266	3266	12 administrator shall also develop a web-based clearinghouse
3267	3267	13 for information available to both job training program
3268	3268	14 graduates and firms participating, directly or indirectly,
3269	3269	15 in Illinois solar incentive programs. The program
3270	3270	16 administrator shall also coordinate its activities with
3271	3271	17 entities implementing electric and natural gas
3272	3272	18 income-qualified energy efficiency programs, including
3273	3273	19 customer referrals to and from such programs, and connect
3274	3274	20 prospective low-income solar customers with any existing
3275	3275	21 deferred maintenance programs where applicable.
3276	3276	22 (6) The long-term renewable resources procurement plan
3277	3277	23 shall also provide for an independent evaluation of the
3278	3278	24 Illinois Solar for All Program. At least every 2 years,
3279	3279	25 the Agency shall select an independent evaluator to review
3280	3280	26 and report on the Illinois Solar for All Program and the
3281	3281
3282	3282
3283	3283
3284	3284
3285	3285
3286	3286	HB3779 - 91 - LRB104 11172 AAS 21254 b
3287	3287
3288	3288
3289	3289	HB3779- 92 -LRB104 11172 AAS 21254 b HB3779 - 92 - LRB104 11172 AAS 21254 b
3290	3290	HB3779 - 92 - LRB104 11172 AAS 21254 b
3291	3291	1 performance of the third-party program administrator of
3292	3292	2 the Illinois Solar for All Program. The evaluation shall
3293	3293	3 be based on objective criteria developed through a public
3294	3294	4 stakeholder process. The process shall include feedback
3295	3295	5 and participation from Illinois Solar for All Program
3296	3296	6 stakeholders, including participants and organizations in
3297	3297	7 environmental justice and historically underserved
3298	3298	8 communities. The report shall include a summary of the
3299	3299	9 evaluation of the Illinois Solar for All Program based on
3300	3300	10 the stakeholder developed objective criteria. The report
3301	3301	11 shall include the number of projects installed; the total
3302	3302	12 installed capacity in kilowatts; the average cost per
3303	3303	13 kilowatt of installed capacity to the extent reasonably
3304	3304	14 obtainable by the Agency; the number of jobs or job
3305	3305	15 opportunities created; economic, social, and environmental
3306	3306	16 benefits created; and the total administrative costs
3307	3307	17 expended by the Agency and program administrator to
3308	3308	18 implement and evaluate the program. The report shall be
3309	3309	19 delivered to the Commission and posted on the Agency's
3310	3310	20 website, and shall be used, as needed, to revise the
3311	3311	21 Illinois Solar for All Program. The Commission shall also
3312	3312	22 consider the results of the evaluation as part of its
3313	3313	23 review of the long-term renewable resources procurement
3314	3314	24 plan under subsection (c) of Section 1-75 of this Act.
3315	3315	25 (7) If additional funding for the programs described
3316	3316	26 in this subsection (b) is available under subsection (k)
3317	3317
3318	3318
3319	3319
3320	3320
3321	3321
3322	3322	HB3779 - 92 - LRB104 11172 AAS 21254 b
3323	3323
3324	3324
3325	3325	HB3779- 93 -LRB104 11172 AAS 21254 b HB3779 - 93 - LRB104 11172 AAS 21254 b
3326	3326	HB3779 - 93 - LRB104 11172 AAS 21254 b
3327	3327	1 of Section 16-108 of the Public Utilities Act, then the
3328	3328	2 Agency shall submit a procurement plan to the Commission
3329	3329	3 no later than September 1, 2018, that proposes how the
3330	3330	4 Agency will procure programs on behalf of the applicable
3331	3331	5 utility. After notice and hearing, the Commission shall
3332	3332	6 approve, or approve with modification, the plan no later
3333	3333	7 than November 1, 2018.
3334	3334	8 (8) As part of the development and update of the
3335	3335	9 long-term renewable resources procurement plan authorized
3336	3336	10 by subsection (c) of Section 1-75 of this Act, the Agency
3337	3337	11 shall plan for: (A) actions to refer customers from the
3338	3338	12 Illinois Solar for All Program to electric and natural gas
3339	3339	13 income-qualified energy efficiency programs, and vice
3340	3340	14 versa, with the goal of increasing participation in both
3341	3341	15 of these programs; (B) effective procedures for data
3342	3342	16 sharing, as needed, to effectuate referrals between the
3343	3343	17 Illinois Solar for All Program and both electric and
3344	3344	18 natural gas income-qualified energy efficiency programs,
3345	3345	19 including sharing customer information directly with the
3346	3346	20 utilities, as needed and appropriate; and (C) efforts to
3347	3347	21 identify any existing deferred maintenance programs for
3348	3348	22 which prospective Solar for All Program customers may be
3349	3349	23 eligible and connect prospective customers for whom
3350	3350	24 deferred maintenance is or may be a barrier to solar
3351	3351	25 installation to those programs.
3352	3352	26 As used in this subsection (b), "low-income households"
3353	3353
3354	3354
3355	3355
3356	3356
3357	3357
3358	3358	HB3779 - 93 - LRB104 11172 AAS 21254 b
3359	3359
3360	3360
3361	3361	HB3779- 94 -LRB104 11172 AAS 21254 b HB3779 - 94 - LRB104 11172 AAS 21254 b
3362	3362	HB3779 - 94 - LRB104 11172 AAS 21254 b
3363	3363	1 means persons and families whose income does not exceed 80% of
3364	3364	2 area median income, adjusted for family size and revised every
3365	3365	3 5 years.
3366	3366	4 For the purposes of this subsection (b), the Agency shall
3367	3367	5 define "environmental justice community" based on the
3368	3368	6 methodologies and findings established by the Agency and the
3369	3369	7 Administrator for the Illinois Solar for All Program in its
3370	3370	8 initial long-term renewable resources procurement plan and as
3371	3371	9 updated by the Agency and the Administrator for the Illinois
3372	3372	10 Solar for All Program as part of the long-term renewable
3373	3373	11 resources procurement plan update.
3374	3374	12 (b-5) After the receipt of all payments required by
3375	3375	13 Section 16-115D of the Public Utilities Act, no additional
3376	3376	14 funds shall be deposited into the Illinois Power Agency
3377	3377	15 Renewable Energy Resources Fund unless directed by order of
3378	3378	16 the Commission.
3379	3379	17 (b-10) After the receipt of all payments required by
3380	3380	18 Section 16-115D of the Public Utilities Act and payment in
3381	3381	19 full of all contracts executed by the Agency under subsections
3382	3382	20 (b) and (i) of this Section, if the balance of the Illinois
3383	3383	21 Power Agency Renewable Energy Resources Fund is under $5,000,
3384	3384	22 then the Fund shall be inoperative and any remaining funds and
3385	3385	23 any funds submitted to the Fund after that date, shall be
3386	3386	24 transferred to the Supplemental Low-Income Energy Assistance
3387	3387	25 Fund for use in the Low-Income Home Energy Assistance Program,
3388	3388	26 as authorized by the Energy Assistance Act.
3389	3389
3390	3390
3391	3391
3392	3392
3393	3393
3394	3394	HB3779 - 94 - LRB104 11172 AAS 21254 b
3395	3395
3396	3396
3397	3397	HB3779- 95 -LRB104 11172 AAS 21254 b HB3779 - 95 - LRB104 11172 AAS 21254 b
3398	3398	HB3779 - 95 - LRB104 11172 AAS 21254 b
3399	3399	1 (b-15) The prevailing wage requirements set forth in the
3400	3400	2 Prevailing Wage Act apply to each project that is undertaken
3401	3401	3 pursuant to one or more of the programs of incentives and
3402	3402	4 initiatives described in subsection (b) of this Section and
3403	3403	5 for which a project application is submitted to the program
3404	3404	6 after the effective date of this amendatory Act of the 103rd
3405	3405	7 General Assembly, except (i) projects that serve single-family
3406	3406	8 or multi-family residential buildings and (ii) projects with
3407	3407	9 an aggregate capacity of less than 100 kilowatts that serve
3408	3408	10 houses of worship. The Agency shall require verification that
3409	3409	11 all construction performed on a project by the renewable
3410	3410	12 energy credit delivery contract holder, its contractors, or
3411	3411	13 its subcontractors relating to the construction of the
3412	3412	14 facility is performed by workers receiving an amount for that
3413	3413	15 work that is greater than or equal to the general prevailing
3414	3414	16 rate of wages as that term is defined in the Prevailing Wage
3415	3415	17 Act, and the Agency may adjust renewable energy credit prices
3416	3416	18 to account for increased labor costs.
3417	3417	19 In this subsection (b-15), "house of worship" has the
3418	3418	20 meaning given in subparagraph (Q) of paragraph (1) of
3419	3419	21 subsection (c) of Section 1-75.
3420	3420	22 (c) (Blank).
3421	3421	23 (d) (Blank).
3422	3422	24 (e) All renewable energy credits procured using monies
3423	3423	25 from the Illinois Power Agency Renewable Energy Resources Fund
3424	3424	26 shall be permanently retired.
3425	3425
3426	3426
3427	3427
3428	3428
3429	3429
3430	3430	HB3779 - 95 - LRB104 11172 AAS 21254 b
3431	3431
3432	3432
3433	3433	HB3779- 96 -LRB104 11172 AAS 21254 b HB3779 - 96 - LRB104 11172 AAS 21254 b
3434	3434	HB3779 - 96 - LRB104 11172 AAS 21254 b
3435	3435	1 (f) The selection of one or more third-party program
3436	3436	2 managers or administrators, the selection of the independent
3437	3437	3 evaluator, and the procurement processes described in this
3438	3438	4 Section are exempt from the requirements of the Illinois
3439	3439	5 Procurement Code, under Section 20-10 of that Code.
3440	3440	6 (g) All disbursements from the Illinois Power Agency
3441	3441	7 Renewable Energy Resources Fund shall be made only upon
3442	3442	8 warrants of the Comptroller drawn upon the Treasurer as
3443	3443	9 custodian of the Fund upon vouchers signed by the Director or
3444	3444	10 by the person or persons designated by the Director for that
3445	3445	11 purpose. The Comptroller is authorized to draw the warrant
3446	3446	12 upon vouchers so signed. The Treasurer shall accept all
3447	3447	13 warrants so signed and shall be released from liability for
3448	3448	14 all payments made on those warrants.
3449	3449	15 (h) The Illinois Power Agency Renewable Energy Resources
3450	3450	16 Fund shall not be subject to sweeps, administrative charges,
3451	3451	17 or chargebacks, including, but not limited to, those
3452	3452	18 authorized under Section 8h of the State Finance Act, that
3453	3453	19 would in any way result in the transfer of any funds from this
3454	3454	20 Fund to any other fund of this State or in having any such
3455	3455	21 funds utilized for any purpose other than the express purposes
3456	3456	22 set forth in this Section.
3457	3457	23 (h-5) The Agency may assess fees to each bidder to recover
3458	3458	24 the costs incurred in connection with a procurement process
3459	3459	25 held under this Section. Fees collected from bidders shall be
3460	3460	26 deposited into the Renewable Energy Resources Fund.
3461	3461
3462	3462
3463	3463
3464	3464
3465	3465
3466	3466	HB3779 - 96 - LRB104 11172 AAS 21254 b
3467	3467
3468	3468
3469	3469	HB3779- 97 -LRB104 11172 AAS 21254 b HB3779 - 97 - LRB104 11172 AAS 21254 b
3470	3470	HB3779 - 97 - LRB104 11172 AAS 21254 b
3471	3471	1 (i) Supplemental procurement process.
3472	3472	2 (1) Within 90 days after June 30, 2014 (the effective
3473	3473	3 date of Public Act 98-672), the Agency shall develop a
3474	3474	4 one-time supplemental procurement plan limited to the
3475	3475	5 procurement of renewable energy credits, if available,
3476	3476	6 from new or existing photovoltaics, including, but not
3477	3477	7 limited to, distributed photovoltaic generation. Nothing
3478	3478	8 in this subsection (i) requires procurement of wind
3479	3479	9 generation through the supplemental procurement.
3480	3480	10 Renewable energy credits procured from new
3481	3481	11 photovoltaics, including, but not limited to, distributed
3482	3482	12 photovoltaic generation, under this subsection (i) must be
3483	3483	13 procured from devices installed by a qualified person. In
3484	3484	14 its supplemental procurement plan, the Agency shall
3485	3485	15 establish contractually enforceable mechanisms for
3486	3486	16 ensuring that the installation of new photovoltaics is
3487	3487	17 performed by a qualified person.
3488	3488	18 For the purposes of this paragraph (1), "qualified
3489	3489	19 person" means a person who performs installations of
3490	3490	20 photovoltaics, including, but not limited to, distributed
3491	3491	21 photovoltaic generation, and who: (A) has completed an
3492	3492	22 apprenticeship as a journeyman electrician from a United
3493	3493	23 States Department of Labor registered electrical
3494	3494	24 apprenticeship and training program and received a
3495	3495	25 certification of satisfactory completion; or (B) does not
3496	3496	26 currently meet the criteria under clause (A) of this
3497	3497
3498	3498
3499	3499
3500	3500
3501	3501
3502	3502	HB3779 - 97 - LRB104 11172 AAS 21254 b
3503	3503
3504	3504
3505	3505	HB3779- 98 -LRB104 11172 AAS 21254 b HB3779 - 98 - LRB104 11172 AAS 21254 b
3506	3506	HB3779 - 98 - LRB104 11172 AAS 21254 b
3507	3507	1 paragraph (1), but is enrolled in a United States
3508	3508	2 Department of Labor registered electrical apprenticeship
3509	3509	3 program, provided that the person is directly supervised
3510	3510	4 by a person who meets the criteria under clause (A) of this
3511	3511	5 paragraph (1); or (C) has obtained one of the following
3512	3512	6 credentials in addition to attesting to satisfactory
3513	3513	7 completion of at least 5 years or 8,000 hours of
3514	3514	8 documented hands-on electrical experience: (i) a North
3515	3515	9 American Board of Certified Energy Practitioners (NABCEP)
3516	3516	10 Installer Certificate for Solar PV; (ii) an Underwriters
3517	3517	11 Laboratories (UL) PV Systems Installer Certificate; (iii)
3518	3518	12 an Electronics Technicians Association, International
3519	3519	13 (ETAI) Level 3 PV Installer Certificate; or (iv) an
3520	3520	14 Associate in Applied Science degree from an Illinois
3521	3521	15 Community College Board approved community college program
3522	3522	16 in renewable energy or a distributed generation
3523	3523	17 technology.
3524	3524	18 For the purposes of this paragraph (1), "directly
3525	3525	19 supervised" means that there is a qualified person who
3526	3526	20 meets the qualifications under clause (A) of this
3527	3527	21 paragraph (1) and who is available for supervision and
3528	3528	22 consultation regarding the work performed by persons under
3529	3529	23 clause (B) of this paragraph (1), including a final
3530	3530	24 inspection of the installation work that has been directly
3531	3531	25 supervised to ensure safety and conformity with applicable
3532	3532	26 codes.
3533	3533
3534	3534
3535	3535
3536	3536
3537	3537
3538	3538	HB3779 - 98 - LRB104 11172 AAS 21254 b
3539	3539
3540	3540
3541	3541	HB3779- 99 -LRB104 11172 AAS 21254 b HB3779 - 99 - LRB104 11172 AAS 21254 b
3542	3542	HB3779 - 99 - LRB104 11172 AAS 21254 b
3543	3543	1 For the purposes of this paragraph (1), "install"
3544	3544	2 means the major activities and actions required to
3545	3545	3 connect, in accordance with applicable building and
3546	3546	4 electrical codes, the conductors, connectors, and all
3547	3547	5 associated fittings, devices, power outlets, or
3548	3548	6 apparatuses mounted at the premises that are directly
3549	3549	7 involved in delivering energy to the premises' electrical
3550	3550	8 wiring from the photovoltaics, including, but not limited
3551	3551	9 to, to distributed photovoltaic generation.
3552	3552	10 The renewable energy credits procured pursuant to the
3553	3553	11 supplemental procurement plan shall be procured using up
3554	3554	12 to $30,000,000 from the Illinois Power Agency Renewable
3555	3555	13 Energy Resources Fund. The Agency shall not plan to use
3556	3556	14 funds from the Illinois Power Agency Renewable Energy
3557	3557	15 Resources Fund in excess of the monies on deposit in such
3558	3558	16 fund or projected to be deposited into such fund. The
3559	3559	17 supplemental procurement plan shall ensure adequate,
3560	3560	18 reliable, affordable, efficient, and environmentally
3561	3561	19 sustainable renewable energy resources (including credits)
3562	3562	20 at the lowest total cost over time, taking into account
3563	3563	21 any benefits of price stability.
3564	3564	22 To the extent available, 50% of the renewable energy
3565	3565	23 credits procured from distributed renewable energy
3566	3566	24 generation shall come from devices of less than 25
3567	3567	25 kilowatts in nameplate capacity. Procurement of renewable
3568	3568	26 energy credits from distributed renewable energy
3569	3569
3570	3570
3571	3571
3572	3572
3573	3573
3574	3574	HB3779 - 99 - LRB104 11172 AAS 21254 b
3575	3575
3576	3576
3577	3577	HB3779- 100 -LRB104 11172 AAS 21254 b HB3779 - 100 - LRB104 11172 AAS 21254 b
3578	3578	HB3779 - 100 - LRB104 11172 AAS 21254 b
3579	3579	1 generation devices shall be done through multi-year
3580	3580	2 contracts of no less than 5 years. The Agency shall create
3581	3581	3 credit requirements for counterparties. In order to
3582	3582	4 minimize the administrative burden on contracting
3583	3583	5 entities, the Agency shall solicit the use of third
3584	3584	6 parties to aggregate distributed renewable energy. These
3585	3585	7 third parties shall enter into and administer contracts
3586	3586	8 with individual distributed renewable energy generation
3587	3587	9 device owners. An individual distributed renewable energy
3588	3588	10 generation device owner shall have the ability to measure
3589	3589	11 the output of his or her distributed renewable energy
3590	3590	12 generation device.
3591	3591	13 In developing the supplemental procurement plan, the
3592	3592	14 Agency shall hold at least one workshop open to the public
3593	3593	15 within 90 days after June 30, 2014 (the effective date of
3594	3594	16 Public Act 98-672) and shall consider any comments made by
3595	3595	17 stakeholders or the public. Upon development of the
3596	3596	18 supplemental procurement plan within this 90-day period,
3597	3597	19 copies of the supplemental procurement plan shall be
3598	3598	20 posted and made publicly available on the Agency's and
3599	3599	21 Commission's websites. All interested parties shall have
3600	3600	22 14 days following the date of posting to provide comment
3601	3601	23 to the Agency on the supplemental procurement plan. All
3602	3602	24 comments submitted to the Agency shall be specific,
3603	3603	25 supported by data or other detailed analyses, and, if
3604	3604	26 objecting to all or a portion of the supplemental
3605	3605
3606	3606
3607	3607
3608	3608
3609	3609
3610	3610	HB3779 - 100 - LRB104 11172 AAS 21254 b
3611	3611
3612	3612
3613	3613	HB3779- 101 -LRB104 11172 AAS 21254 b HB3779 - 101 - LRB104 11172 AAS 21254 b
3614	3614	HB3779 - 101 - LRB104 11172 AAS 21254 b
3615	3615	1 procurement plan, accompanied by specific alternative
3616	3616	2 wording or proposals. All comments shall be posted on the
3617	3617	3 Agency's and Commission's websites. Within 14 days
3618	3618	4 following the end of the 14-day review period, the Agency
3619	3619	5 shall revise the supplemental procurement plan as
3620	3620	6 necessary based on the comments received and file its
3621	3621	7 revised supplemental procurement plan with the Commission
3622	3622	8 for approval.
3623	3623	9 (2) Within 5 days after the filing of the supplemental
3624	3624	10 procurement plan at the Commission, any person objecting
3625	3625	11 to the supplemental procurement plan shall file an
3626	3626	12 objection with the Commission. Within 10 days after the
3627	3627	13 filing, the Commission shall determine whether a hearing
3628	3628	14 is necessary. The Commission shall enter its order
3629	3629	15 confirming or modifying the supplemental procurement plan
3630	3630	16 within 90 days after the filing of the supplemental
3631	3631	17 procurement plan by the Agency.
3632	3632	18 (3) The Commission shall approve the supplemental
3633	3633	19 procurement plan of renewable energy credits to be
3634	3634	20 procured from new or existing photovoltaics, including,
3635	3635	21 but not limited to, distributed photovoltaic generation,
3636	3636	22 if the Commission determines that it will ensure adequate,
3637	3637	23 reliable, affordable, efficient, and environmentally
3638	3638	24 sustainable electric service in the form of renewable
3639	3639	25 energy credits at the lowest total cost over time, taking
3640	3640	26 into account any benefits of price stability.
3641	3641
3642	3642
3643	3643
3644	3644
3645	3645
3646	3646	HB3779 - 101 - LRB104 11172 AAS 21254 b
3647	3647
3648	3648
3649	3649	HB3779- 102 -LRB104 11172 AAS 21254 b HB3779 - 102 - LRB104 11172 AAS 21254 b
3650	3650	HB3779 - 102 - LRB104 11172 AAS 21254 b
3651	3651	1 (4) The supplemental procurement process under this
3652	3652	2 subsection (i) shall include each of the following
3653	3653	3 components:
3654	3654	4 (A) Procurement administrator. The Agency may
3655	3655	5 retain a procurement administrator in the manner set
3656	3656	6 forth in item (2) of subsection (a) of Section 1-75 of
3657	3657	7 this Act to conduct the supplemental procurement or
3658	3658	8 may elect to use the same procurement administrator
3659	3659	9 administering the Agency's annual procurement under
3660	3660	10 Section 1-75.
3661	3661	11 (B) Procurement monitor. The procurement monitor
3662	3662	12 retained by the Commission pursuant to Section
3663	3663	13 16-111.5 of the Public Utilities Act shall:
3664	3664	14 (i) monitor interactions among the procurement
3665	3665	15 administrator and bidders and suppliers;
3666	3666	16 (ii) monitor and report to the Commission on
3667	3667	17 the progress of the supplemental procurement
3668	3668	18 process;
3669	3669	19 (iii) provide an independent confidential
3670	3670	20 report to the Commission regarding the results of
3671	3671	21 the procurement events;
3672	3672	22 (iv) assess compliance with the procurement
3673	3673	23 plan approved by the Commission for the
3674	3674	24 supplemental procurement process;
3675	3675	25 (v) preserve the confidentiality of supplier
3676	3676	26 and bidding information in a manner consistent
3677	3677
3678	3678
3679	3679
3680	3680
3681	3681
3682	3682	HB3779 - 102 - LRB104 11172 AAS 21254 b
3683	3683
3684	3684
3685	3685	HB3779- 103 -LRB104 11172 AAS 21254 b HB3779 - 103 - LRB104 11172 AAS 21254 b
3686	3686	HB3779 - 103 - LRB104 11172 AAS 21254 b
3687	3687	1 with all applicable laws, rules, regulations, and
3688	3688	2 tariffs;
3689	3689	3 (vi) provide expert advice to the Commission
3690	3690	4 and consult with the procurement administrator
3691	3691	5 regarding issues related to procurement process
3692	3692	6 design, rules, protocols, and policy-related
3693	3693	7 matters;
3694	3694	8 (vii) consult with the procurement
3695	3695	9 administrator regarding the development and use of
3696	3696	10 benchmark criteria, standard form contracts,
3697	3697	11 credit policies, and bid documents; and
3698	3698	12 (viii) perform, with respect to the
3699	3699	13 supplemental procurement process, any other
3700	3700	14 procurement monitor duties specifically delineated
3701	3701	15 within subsection (i) of this Section.
3702	3702	16 (C) Solicitation, prequalification, and
3703	3703	17 registration of bidders. The procurement administrator
3704	3704	18 shall disseminate information to potential bidders to
3705	3705	19 promote a procurement event, notify potential bidders
3706	3706	20 that the procurement administrator may enter into a
3707	3707	21 post-bid price negotiation with bidders that meet the
3708	3708	22 applicable benchmarks, provide supply requirements,
3709	3709	23 and otherwise explain the competitive procurement
3710	3710	24 process. In addition to such other publication as the
3711	3711	25 procurement administrator determines is appropriate,
3712	3712	26 this information shall be posted on the Agency's and
3713	3713
3714	3714
3715	3715
3716	3716
3717	3717
3718	3718	HB3779 - 103 - LRB104 11172 AAS 21254 b
3719	3719
3720	3720
3721	3721	HB3779- 104 -LRB104 11172 AAS 21254 b HB3779 - 104 - LRB104 11172 AAS 21254 b
3722	3722	HB3779 - 104 - LRB104 11172 AAS 21254 b
3723	3723	1 the Commission's websites. The procurement
3724	3724	2 administrator shall also administer the
3725	3725	3 prequalification process, including evaluation of
3726	3726	4 credit worthiness, compliance with procurement rules,
3727	3727	5 and agreement to the standard form contract developed
3728	3728	6 pursuant to item (D) of this paragraph (4). The
3729	3729	7 procurement administrator shall then identify and
3730	3730	8 register bidders to participate in the procurement
3731	3731	9 event.
3732	3732	10 (D) Standard contract forms and credit terms and
3733	3733	11 instruments. The procurement administrator, in
3734	3734	12 consultation with the Agency, the Commission, and
3735	3735	13 other interested parties and subject to Commission
3736	3736	14 oversight, shall develop and provide standard contract
3737	3737	15 forms for the supplier contracts that meet generally
3738	3738	16 accepted industry practices as well as include any
3739	3739	17 applicable State of Illinois terms and conditions that
3740	3740	18 are required for contracts entered into by an agency
3741	3741	19 of the State of Illinois. Standard credit terms and
3742	3742	20 instruments that meet generally accepted industry
3743	3743	21 practices shall be similarly developed. Contracts for
3744	3744	22 new photovoltaics shall include a provision attesting
3745	3745	23 that the supplier will use a qualified person for the
3746	3746	24 installation of the device pursuant to paragraph (1)
3747	3747	25 of subsection (i) of this Section. The procurement
3748	3748	26 administrator shall make available to the Commission
3749	3749
3750	3750
3751	3751
3752	3752
3753	3753
3754	3754	HB3779 - 104 - LRB104 11172 AAS 21254 b
3755	3755
3756	3756
3757	3757	HB3779- 105 -LRB104 11172 AAS 21254 b HB3779 - 105 - LRB104 11172 AAS 21254 b
3758	3758	HB3779 - 105 - LRB104 11172 AAS 21254 b
3759	3759	1 all written comments it receives on the contract
3760	3760	2 forms, credit terms, or instruments. If the
3761	3761	3 procurement administrator cannot reach agreement with
3762	3762	4 the parties as to the contract terms and conditions,
3763	3763	5 the procurement administrator must notify the
3764	3764	6 Commission of any disputed terms and the Commission
3765	3765	7 shall resolve the dispute. The terms of the contracts
3766	3766	8 shall not be subject to negotiation by winning
3767	3767	9 bidders, and the bidders must agree to the terms of the
3768	3768	10 contract in advance so that winning bids are selected
3769	3769	11 solely on the basis of price.
3770	3770	12 (E) Requests for proposals; competitive
3771	3771	13 procurement process. The procurement administrator
3772	3772	14 shall design and issue requests for proposals to
3773	3773	15 supply renewable energy credits in accordance with the
3774	3774	16 supplemental procurement plan, as approved by the
3775	3775	17 Commission. The requests for proposals shall set forth
3776	3776	18 a procedure for sealed, binding commitment bidding
3777	3777	19 with pay-as-bid settlement, and provision for
3778	3778	20 selection of bids on the basis of price, provided,
3779	3779	21 however, that no bid shall be accepted if it exceeds
3780	3780	22 the benchmark developed pursuant to item (F) of this
3781	3781	23 paragraph (4).
3782	3782	24 (F) Benchmarks. Benchmarks for each product to be
3783	3783	25 procured shall be developed by the procurement
3784	3784	26 administrator in consultation with Commission staff,
3785	3785
3786	3786
3787	3787
3788	3788
3789	3789
3790	3790	HB3779 - 105 - LRB104 11172 AAS 21254 b
3791	3791
3792	3792
3793	3793	HB3779- 106 -LRB104 11172 AAS 21254 b HB3779 - 106 - LRB104 11172 AAS 21254 b
3794	3794	HB3779 - 106 - LRB104 11172 AAS 21254 b
3795	3795	1 the Agency, and the procurement monitor for use in
3796	3796	2 this supplemental procurement.
3797	3797	3 (G) A plan for implementing contingencies in the
3798	3798	4 event of supplier default, Commission rejection of
3799	3799	5 results, or any other cause.
3800	3800	6 (5) Within 2 business days after opening the sealed
3801	3801	7 bids, the procurement administrator shall submit a
3802	3802	8 confidential report to the Commission. The report shall
3803	3803	9 contain the results of the bidding for each of the
3804	3804	10 products along with the procurement administrator's
3805	3805	11 recommendation for the acceptance and rejection of bids
3806	3806	12 based on the price benchmark criteria and other factors
3807	3807	13 observed in the process. The procurement monitor also
3808	3808	14 shall submit a confidential report to the Commission
3809	3809	15 within 2 business days after opening the sealed bids. The
3810	3810	16 report shall contain the procurement monitor's assessment
3811	3811	17 of bidder behavior in the process as well as an assessment
3812	3812	18 of the procurement administrator's compliance with the
3813	3813	19 procurement process and rules. The Commission shall review
3814	3814	20 the confidential reports submitted by the procurement
3815	3815	21 administrator and procurement monitor and shall accept or
3816	3816	22 reject the recommendations of the procurement
3817	3817	23 administrator within 2 business days after receipt of the
3818	3818	24 reports.
3819	3819	25 (6) Within 3 business days after the Commission
3820	3820	26 decision approving the results of a procurement event, the
3821	3821
3822	3822
3823	3823
3824	3824
3825	3825
3826	3826	HB3779 - 106 - LRB104 11172 AAS 21254 b
3827	3827
3828	3828
3829	3829	HB3779- 107 -LRB104 11172 AAS 21254 b HB3779 - 107 - LRB104 11172 AAS 21254 b
3830	3830	HB3779 - 107 - LRB104 11172 AAS 21254 b
3831	3831	1 Agency shall enter into binding contractual arrangements
3832	3832	2 with the winning suppliers using the standard form
3833	3833	3 contracts.
3834	3834	4 (7) The names of the successful bidders and the
3835	3835	5 average of the winning bid prices for each contract type
3836	3836	6 and for each contract term shall be made available to the
3837	3837	7 public within 2 days after the supplemental procurement
3838	3838	8 event. The Commission, the procurement monitor, the
3839	3839	9 procurement administrator, the Agency, and all
3840	3840	10 participants in the procurement process shall maintain the
3841	3841	11 confidentiality of all other supplier and bidding
3842	3842	12 information in a manner consistent with all applicable
3843	3843	13 laws, rules, regulations, and tariffs. Confidential
3844	3844	14 information, including the confidential reports submitted
3845	3845	15 by the procurement administrator and procurement monitor
3846	3846	16 pursuant to this Section, shall not be made publicly
3847	3847	17 available and shall not be discoverable by any party in
3848	3848	18 any proceeding, absent a compelling demonstration of need,
3849	3849	19 nor shall those reports be admissible in any proceeding
3850	3850	20 other than one for law enforcement purposes.
3851	3851	21 (8) The supplemental procurement provided in this
3852	3852	22 subsection (i) shall not be subject to the requirements
3853	3853	23 and limitations of subsections (c) and (d) of this
3854	3854	24 Section.
3855	3855	25 (9) Expenses incurred in connection with the
3856	3856	26 procurement process held pursuant to this Section,
3857	3857
3858	3858
3859	3859
3860	3860
3861	3861
3862	3862	HB3779 - 107 - LRB104 11172 AAS 21254 b
3863	3863
3864	3864
3865	3865	HB3779- 108 -LRB104 11172 AAS 21254 b HB3779 - 108 - LRB104 11172 AAS 21254 b
3866	3866	HB3779 - 108 - LRB104 11172 AAS 21254 b
3867	3867	1 including, but not limited to, the cost of developing the
3868	3868	2 supplemental procurement plan, the procurement
3869	3869	3 administrator, procurement monitor, and the cost of the
3870	3870	4 retirement of renewable energy credits purchased pursuant
3871	3871	5 to the supplemental procurement shall be paid for from the
3872	3872	6 Illinois Power Agency Renewable Energy Resources Fund. The
3873	3873	7 Agency shall enter into an interagency agreement with the
3874	3874	8 Commission to reimburse the Commission for its costs
3875	3875	9 associated with the procurement monitor for the
3876	3876	10 supplemental procurement process.
3877	3877	11 (Source: P.A. 102-662, eff. 9-15-21; 103-188, eff. 6-30-23;
3878	3878	12 103-605, eff. 7-1-24.)
3879	3879	13 (20 ILCS 3855/1-75)
3880	3880	14 Sec. 1-75. Planning and Procurement Bureau. The Planning
3881	3881	15 and Procurement Bureau has the following duties and
3882	3882	16 responsibilities:
3883	3883	17 (a) The Planning and Procurement Bureau shall each year,
3884	3884	18 beginning in 2008, develop procurement plans and conduct
3885	3885	19 competitive procurement processes in accordance with the
3886	3886	20 requirements of Section 16-111.5 of the Public Utilities Act
3887	3887	21 for the eligible retail customers of electric utilities that
3888	3888	22 on December 31, 2005 provided electric service to at least
3889	3889	23 100,000 customers in Illinois. Beginning with the delivery
3890	3890	24 year commencing on June 1, 2017, the Planning and Procurement
3891	3891	25 Bureau shall develop plans and processes for the procurement
3892	3892
3893	3893
3894	3894
3895	3895
3896	3896
3897	3897	HB3779 - 108 - LRB104 11172 AAS 21254 b
3898	3898
3899	3899
3900	3900	HB3779- 109 -LRB104 11172 AAS 21254 b HB3779 - 109 - LRB104 11172 AAS 21254 b
3901	3901	HB3779 - 109 - LRB104 11172 AAS 21254 b
3902	3902	1 of zero emission credits from zero emission facilities in
3903	3903	2 accordance with the requirements of subsection (d-5) of this
3904	3904	3 Section. Beginning on the effective date of this amendatory
3905	3905	4 Act of the 102nd General Assembly, the Planning and
3906	3906	5 Procurement Bureau shall develop plans and processes for the
3907	3907	6 procurement of carbon mitigation credits from carbon-free
3908	3908	7 energy resources in accordance with the requirements of
3909	3909	8 subsection (d-10) of this Section. Beginning on the effective
3910	3910	9 date of this amendatory Act of the 104th General Assembly, the
3911	3911	10 Planning and Procurement Bureau shall develop plans and
3912	3912	11 processes for the procurement of energy storage in accordance
3913	3913	12 with the requirements of Section 1-93 of this Act and Section
3914	3914	13 16-111.5 of the Public Utilities Act. The Planning and
3915	3915	14 Procurement Bureau shall also develop procurement plans and
3916	3916	15 conduct competitive procurement processes in accordance with
3917	3917	16 the requirements of Section 16-111.5 of the Public Utilities
3918	3918	17 Act for the eligible retail customers of small
3919	3919	18 multi-jurisdictional electric utilities that (i) on December
3920	3920	19 31, 2005 served less than 100,000 customers in Illinois and
3921	3921	20 (ii) request a procurement plan for their Illinois
3922	3922	21 jurisdictional load. This Section shall not apply to a small
3923	3923	22 multi-jurisdictional utility until such time as a small
3924	3924	23 multi-jurisdictional utility requests the Agency to prepare a
3925	3925	24 procurement plan for their Illinois jurisdictional load. For
3926	3926	25 the purposes of this Section, the term "eligible retail
3927	3927	26 customers" has the same definition as found in Section
3928	3928
3929	3929
3930	3930
3931	3931
3932	3932
3933	3933	HB3779 - 109 - LRB104 11172 AAS 21254 b
3934	3934
3935	3935
3936	3936	HB3779- 110 -LRB104 11172 AAS 21254 b HB3779 - 110 - LRB104 11172 AAS 21254 b
3937	3937	HB3779 - 110 - LRB104 11172 AAS 21254 b
3938	3938	1 16-111.5(a) of the Public Utilities Act.
3939	3939	2 Beginning with the plan or plans to be implemented in the
3940	3940	3 2017 delivery year, the Agency shall no longer include the
3941	3941	4 procurement of renewable energy resources in the annual
3942	3942	5 procurement plans required by this subsection (a), except as
3943	3943	6 provided in subsection (q) of Section 16-111.5 of the Public
3944	3944	7 Utilities Act, and shall instead develop a long-term renewable
3945	3945	8 resources procurement plan in accordance with subsection (c)
3946	3946	9 of this Section and Section 16-111.5 of the Public Utilities
3947	3947	10 Act.
3948	3948	11 In accordance with subsection (c-5) of this Section, the
3949	3949	12 Planning and Procurement Bureau shall oversee the procurement
3950	3950	13 by electric utilities that served more than 300,000 retail
3951	3951	14 customers in this State as of January 1, 2019 of renewable
3952	3952	15 energy credits from new utility-scale solar projects to be
3953	3953	16 installed, along with energy storage facilities, at or
3954	3954	17 adjacent to the sites of electric generating facilities that,
3955	3955	18 as of January 1, 2016, burned coal as their primary fuel
3956	3956	19 source.
3957	3957	20 (1) The Agency shall each year, beginning in 2008, as
3958	3958	21 needed, issue a request for qualifications for experts or
3959	3959	22 expert consulting firms to develop the procurement plans
3960	3960	23 in accordance with Section 16-111.5 of the Public
3961	3961	24 Utilities Act. In order to qualify an expert or expert
3962	3962	25 consulting firm must have:
3963	3963	26 (A) direct previous experience assembling
3964	3964
3965	3965
3966	3966
3967	3967
3968	3968
3969	3969	HB3779 - 110 - LRB104 11172 AAS 21254 b
3970	3970
3971	3971
3972	3972	HB3779- 111 -LRB104 11172 AAS 21254 b HB3779 - 111 - LRB104 11172 AAS 21254 b
3973	3973	HB3779 - 111 - LRB104 11172 AAS 21254 b
3974	3974	1 large-scale power supply plans or portfolios for
3975	3975	2 end-use customers;
3976	3976	3 (B) an advanced degree in economics, mathematics,
3977	3977	4 engineering, risk management, or a related area of
3978	3978	5 study;
3979	3979	6 (C) 10 years of experience in the electricity
3980	3980	7 sector, including managing supply risk;
3981	3981	8 (D) expertise in wholesale electricity market
3982	3982	9 rules, including those established by the Federal
3983	3983	10 Energy Regulatory Commission and regional transmission
3984	3984	11 organizations;
3985	3985	12 (E) expertise in credit protocols and familiarity
3986	3986	13 with contract protocols;
3987	3987	14 (F) adequate resources to perform and fulfill the
3988	3988	15 required functions and responsibilities; and
3989	3989	16 (G) the absence of a conflict of interest and
3990	3990	17 inappropriate bias for or against potential bidders or
3991	3991	18 the affected electric utilities.
3992	3992	19 (2) The Agency shall each year, as needed, issue a
3993	3993	20 request for qualifications for a procurement administrator
3994	3994	21 to conduct the competitive procurement processes in
3995	3995	22 accordance with Section 16-111.5 of the Public Utilities
3996	3996	23 Act. In order to qualify an expert or expert consulting
3997	3997	24 firm must have:
3998	3998	25 (A) direct previous experience administering a
3999	3999	26 large-scale competitive procurement process;
4000	4000
4001	4001
4002	4002
4003	4003
4004	4004
4005	4005	HB3779 - 111 - LRB104 11172 AAS 21254 b
4006	4006
4007	4007
4008	4008	HB3779- 112 -LRB104 11172 AAS 21254 b HB3779 - 112 - LRB104 11172 AAS 21254 b
4009	4009	HB3779 - 112 - LRB104 11172 AAS 21254 b
4010	4010	1 (B) an advanced degree in economics, mathematics,
4011	4011	2 engineering, or a related area of study;
4012	4012	3 (C) 10 years of experience in the electricity
4013	4013	4 sector, including risk management experience;
4014	4014	5 (D) expertise in wholesale electricity market
4015	4015	6 rules, including those established by the Federal
4016	4016	7 Energy Regulatory Commission and regional transmission
4017	4017	8 organizations;
4018	4018	9 (E) expertise in credit and contract protocols;
4019	4019	10 (F) adequate resources to perform and fulfill the
4020	4020	11 required functions and responsibilities; and
4021	4021	12 (G) the absence of a conflict of interest and
4022	4022	13 inappropriate bias for or against potential bidders or
4023	4023	14 the affected electric utilities.
4024	4024	15 (3) The Agency shall provide affected utilities and
4025	4025	16 other interested parties with the lists of qualified
4026	4026	17 experts or expert consulting firms identified through the
4027	4027	18 request for qualifications processes that are under
4028	4028	19 consideration to develop the procurement plans and to
4029	4029	20 serve as the procurement administrator. The Agency shall
4030	4030	21 also provide each qualified expert's or expert consulting
4031	4031	22 firm's response to the request for qualifications. All
4032	4032	23 information provided under this subparagraph shall also be
4033	4033	24 provided to the Commission. The Agency may provide by rule
4034	4034	25 for fees associated with supplying the information to
4035	4035	26 utilities and other interested parties. These parties
4036	4036
4037	4037
4038	4038
4039	4039
4040	4040
4041	4041	HB3779 - 112 - LRB104 11172 AAS 21254 b
4042	4042
4043	4043
4044	4044	HB3779- 113 -LRB104 11172 AAS 21254 b HB3779 - 113 - LRB104 11172 AAS 21254 b
4045	4045	HB3779 - 113 - LRB104 11172 AAS 21254 b
4046	4046	1 shall, within 5 business days, notify the Agency in
4047	4047	2 writing if they object to any experts or expert consulting
4048	4048	3 firms on the lists. Objections shall be based on:
4049	4049	4 (A) failure to satisfy qualification criteria;
4050	4050	5 (B) identification of a conflict of interest; or
4051	4051	6 (C) evidence of inappropriate bias for or against
4052	4052	7 potential bidders or the affected utilities.
4053	4053	8 The Agency shall remove experts or expert consulting
4054	4054	9 firms from the lists within 10 days if there is a
4055	4055	10 reasonable basis for an objection and provide the updated
4056	4056	11 lists to the affected utilities and other interested
4057	4057	12 parties. If the Agency fails to remove an expert or expert
4058	4058	13 consulting firm from a list, an objecting party may seek
4059	4059	14 review by the Commission within 5 days thereafter by
4060	4060	15 filing a petition, and the Commission shall render a
4061	4061	16 ruling on the petition within 10 days. There is no right of
4062	4062	17 appeal of the Commission's ruling.
4063	4063	18 (4) The Agency shall issue requests for proposals to
4064	4064	19 the qualified experts or expert consulting firms to
4065	4065	20 develop a procurement plan for the affected utilities and
4066	4066	21 to serve as procurement administrator.
4067	4067	22 (5) The Agency shall select an expert or expert
4068	4068	23 consulting firm to develop procurement plans based on the
4069	4069	24 proposals submitted and shall award contracts of up to 5
4070	4070	25 years to those selected.
4071	4071	26 (6) The Agency shall select an expert or expert
4072	4072
4073	4073
4074	4074
4075	4075
4076	4076
4077	4077	HB3779 - 113 - LRB104 11172 AAS 21254 b
4078	4078
4079	4079
4080	4080	HB3779- 114 -LRB104 11172 AAS 21254 b HB3779 - 114 - LRB104 11172 AAS 21254 b
4081	4081	HB3779 - 114 - LRB104 11172 AAS 21254 b
4082	4082	1 consulting firm, with approval of the Commission, to serve
4083	4083	2 as procurement administrator based on the proposals
4084	4084	3 submitted. If the Commission rejects, within 5 days, the
4085	4085	4 Agency's selection, the Agency shall submit another
4086	4086	5 recommendation within 3 days based on the proposals
4087	4087	6 submitted. The Agency shall award a 5-year contract to the
4088	4088	7 expert or expert consulting firm so selected with
4089	4089	8 Commission approval.
4090	4090	9 (b) The experts or expert consulting firms retained by the
4091	4091	10 Agency shall, as appropriate, prepare procurement plans, and
4092	4092	11 conduct a competitive procurement process as prescribed in
4093	4093	12 Section 16-111.5 of the Public Utilities Act, to ensure
4094	4094	13 adequate, reliable, affordable, efficient, and environmentally
4095	4095	14 sustainable electric service at the lowest total cost over
4096	4096	15 time, taking into account any benefits of price stability, for
4097	4097	16 eligible retail customers of electric utilities that on
4098	4098	17 December 31, 2005 provided electric service to at least
4099	4099	18 100,000 customers in the State of Illinois, and for eligible
4100	4100	19 Illinois retail customers of small multi-jurisdictional
4101	4101	20 electric utilities that (i) on December 31, 2005 served less
4102	4102	21 than 100,000 customers in Illinois and (ii) request a
4103	4103	22 procurement plan for their Illinois jurisdictional load.
4104	4104	23 (c) Renewable portfolio standard.
4105	4105	24 (1)(A) The Agency shall develop a long-term renewable
4106	4106	25 resources procurement plan that shall include procurement
4107	4107	26 programs and competitive procurement events necessary to
4108	4108
4109	4109
4110	4110
4111	4111
4112	4112
4113	4113	HB3779 - 114 - LRB104 11172 AAS 21254 b
4114	4114
4115	4115
4116	4116	HB3779- 115 -LRB104 11172 AAS 21254 b HB3779 - 115 - LRB104 11172 AAS 21254 b
4117	4117	HB3779 - 115 - LRB104 11172 AAS 21254 b
4118	4118	1 meet the goals set forth in this subsection (c). The
4119	4119	2 initial long-term renewable resources procurement plan
4120	4120	3 shall be released for comment no later than 160 days after
4121	4121	4 June 1, 2017 (the effective date of Public Act 99-906).
4122	4122	5 The Agency shall review, and may revise on an expedited
4123	4123	6 basis, the long-term renewable resources procurement plan
4124	4124	7 at least every 2 years, which shall be conducted in
4125	4125	8 conjunction with the procurement plan under Section
4126	4126	9 16-111.5 of the Public Utilities Act to the extent
4127	4127	10 practicable to minimize administrative expense. No later
4128	4128	11 than 120 days after the effective date of this amendatory
4129	4129	12 Act of the 103rd General Assembly, the Agency shall
4130	4130	13 release for comment a revision to the long-term renewable
4131	4131	14 resources procurement plan, updating elements of the most
4132	4132	15 recently approved plan as needed to comply with this
4133	4133	16 amendatory Act of the 103rd General Assembly, and any
4134	4134	17 long-term renewable resources procurement plan update
4135	4135	18 published by the Agency but not yet approved by the
4136	4136	19 Illinois Commerce Commission shall be withdrawn. The
4137	4137	20 long-term renewable resources procurement plans shall be
4138	4138	21 subject to review and approval by the Commission under
4139	4139	22 Section 16-111.5 of the Public Utilities Act.
4140	4140	23 (B) Subject to subparagraph (F) of this paragraph (1),
4141	4141	24 the long-term renewable resources procurement plan shall
4142	4142	25 attempt to meet the goals for procurement of renewable
4143	4143	26 energy credits at levels of at least the following overall
4144	4144
4145	4145
4146	4146
4147	4147
4148	4148
4149	4149	HB3779 - 115 - LRB104 11172 AAS 21254 b
4150	4150
4151	4151
4152	4152	HB3779- 116 -LRB104 11172 AAS 21254 b HB3779 - 116 - LRB104 11172 AAS 21254 b
4153	4153	HB3779 - 116 - LRB104 11172 AAS 21254 b
4154	4154	1 percentages: 13% by the 2017 delivery year; increasing by
4155	4155	2 at least 1.5% each delivery year thereafter to at least
4156	4156	3 25% by the 2025 delivery year; increasing by at least 3%
4157	4157	4 each delivery year thereafter to at least 40% by the 2030
4158	4158	5 delivery year, and continuing at no less than 40% for each
4159	4159	6 delivery year thereafter. The Agency shall attempt to
4160	4160	7 procure 50% by delivery year 2040. The Agency shall
4161	4161	8 determine the annual increase between delivery year 2030
4162	4162	9 and delivery year 2040, if any, taking into account energy
4163	4163	10 demand, other energy resources, and other public policy
4164	4164	11 goals. In the event of a conflict between these goals and
4165	4165	12 the new wind, new photovoltaic, and hydropower procurement
4166	4166	13 requirements described in items (i) through (iii) of
4167	4167	14 subparagraph (C) of this paragraph (1), the long-term plan
4168	4168	15 shall prioritize compliance with the new wind, new
4169	4169	16 photovoltaic, and hydropower procurement requirements
4170	4170	17 described in items (i) through (iii) of subparagraph (C)
4171	4171	18 of this paragraph (1) over the annual percentage targets
4172	4172	19 described in this subparagraph (B). The Agency shall not
4173	4173	20 comply with the annual percentage targets described in
4174	4174	21 this subparagraph (B) by procuring renewable energy
4175	4175	22 credits that are unlikely to lead to the development of
4176	4176	23 new renewable resources or new, modernized, or retooled
4177	4177	24 hydropower facilities.
4178	4178	25 For the delivery year beginning June 1, 2017, the
4179	4179	26 procurement plan shall attempt to include, subject to the
4180	4180
4181	4181
4182	4182
4183	4183
4184	4184
4185	4185	HB3779 - 116 - LRB104 11172 AAS 21254 b
4186	4186
4187	4187
4188	4188	HB3779- 117 -LRB104 11172 AAS 21254 b HB3779 - 117 - LRB104 11172 AAS 21254 b
4189	4189	HB3779 - 117 - LRB104 11172 AAS 21254 b
4190	4190	1 prioritization outlined in this subparagraph (B),
4191	4191	2 cost-effective renewable energy resources equal to at
4192	4192	3 least 13% of each utility's load for eligible retail
4193	4193	4 customers and 13% of the applicable portion of each
4194	4194	5 utility's load for retail customers who are not eligible
4195	4195	6 retail customers, which applicable portion shall equal 50%
4196	4196	7 of the utility's load for retail customers who are not
4197	4197	8 eligible retail customers on February 28, 2017.
4198	4198	9 For the delivery year beginning June 1, 2018, the
4199	4199	10 procurement plan shall attempt to include, subject to the
4200	4200	11 prioritization outlined in this subparagraph (B),
4201	4201	12 cost-effective renewable energy resources equal to at
4202	4202	13 least 14.5% of each utility's load for eligible retail
4203	4203	14 customers and 14.5% of the applicable portion of each
4204	4204	15 utility's load for retail customers who are not eligible
4205	4205	16 retail customers, which applicable portion shall equal 75%
4206	4206	17 of the utility's load for retail customers who are not
4207	4207	18 eligible retail customers on February 28, 2017.
4208	4208	19 For the delivery year beginning June 1, 2019, and for
4209	4209	20 each year thereafter, the procurement plans shall attempt
4210	4210	21 to include, subject to the prioritization outlined in this
4211	4211	22 subparagraph (B), cost-effective renewable energy
4212	4212	23 resources equal to a minimum percentage of each utility's
4213	4213	24 load for all retail customers as follows: 16% by June 1,
4214	4214	25 2019; increasing by 1.5% each year thereafter to 25% by
4215	4215	26 June 1, 2025; and 25% by June 1, 2026; increasing by at
4216	4216
4217	4217
4218	4218
4219	4219
4220	4220
4221	4221	HB3779 - 117 - LRB104 11172 AAS 21254 b
4222	4222
4223	4223
4224	4224	HB3779- 118 -LRB104 11172 AAS 21254 b HB3779 - 118 - LRB104 11172 AAS 21254 b
4225	4225	HB3779 - 118 - LRB104 11172 AAS 21254 b
4226	4226	1 least 3% each delivery year thereafter to at least 40% by
4227	4227	2 the 2030 delivery year, and continuing at no less than 40%
4228	4228	3 for each delivery year thereafter. The Agency shall
4229	4229	4 attempt to procure 50% by delivery year 2040. The Agency
4230	4230	5 shall determine the annual increase between delivery year
4231	4231	6 2030 and delivery year 2040, if any, taking into account
4232	4232	7 energy demand, other energy resources, and other public
4233	4233	8 policy goals.
4234	4234	9 For each delivery year, the Agency shall first
4235	4235	10 recognize each utility's obligations for that delivery
4236	4236	11 year under existing contracts. Any renewable energy
4237	4237	12 credits under existing contracts, including renewable
4238	4238	13 energy credits as part of renewable energy resources,
4239	4239	14 shall be used to meet the goals set forth in this
4240	4240	15 subsection (c) for the delivery year.
4241	4241	16 (C) The long-term renewable resources procurement plan
4242	4242	17 described in subparagraph (A) of this paragraph (1) shall
4243	4243	18 include the procurement of renewable energy credits from
4244	4244	19 new projects pursuant to the following terms:
4245	4245	20 (i) At least 10,000,000 renewable energy credits
4246	4246	21 delivered annually by the end of the 2021 delivery
4247	4247	22 year, and increasing ratably to reach 45,000,000
4248	4248	23 renewable energy credits delivered annually from new
4249	4249	24 wind and solar projects by the end of delivery year
4250	4250	25 2030 such that the goals in subparagraph (B) of this
4251	4251	26 paragraph (1) are met entirely by procurements of
4252	4252
4253	4253
4254	4254
4255	4255
4256	4256
4257	4257	HB3779 - 118 - LRB104 11172 AAS 21254 b
4258	4258
4259	4259
4260	4260	HB3779- 119 -LRB104 11172 AAS 21254 b HB3779 - 119 - LRB104 11172 AAS 21254 b
4261	4261	HB3779 - 119 - LRB104 11172 AAS 21254 b
4262	4262	1 renewable energy credits from new wind and
4263	4263	2 photovoltaic projects. Of that amount, to the extent
4264	4264	3 possible, the Agency shall procure 45% from wind and
4265	4265	4 hydropower projects and 55% from photovoltaic
4266	4266	5 projects. Of the amount to be procured from
4267	4267	6 photovoltaic projects, the Agency shall procure: at
4268	4268	7 least 50% from solar photovoltaic projects using the
4269	4269	8 program outlined in subparagraph (K) of this paragraph
4270	4270	9 (1) from distributed renewable energy generation
4271	4271	10 devices or community renewable generation projects; at
4272	4272	11 least 47% from utility-scale solar projects; at least
4273	4273	12 3% from brownfield site photovoltaic projects that are
4274	4274	13 not community renewable generation projects.
4275	4275	14 In developing the long-term renewable resources
4276	4276	15 procurement plan, the Agency shall consider other
4277	4277	16 approaches, in addition to competitive procurements,
4278	4278	17 that can be used to procure renewable energy credits
4279	4279	18 from brownfield site photovoltaic projects and thereby
4280	4280	19 help return blighted or contaminated land to
4281	4281	20 productive use while enhancing public health and the
4282	4282	21 well-being of Illinois residents, including those in
4283	4283	22 environmental justice communities, as defined using
4284	4284	23 existing methodologies and findings used by the Agency
4285	4285	24 and its Administrator in its Illinois Solar for All
4286	4286	25 Program. The Agency shall also consider other
4287	4287	26 approaches, in addition to competitive procurements,
4288	4288
4289	4289
4290	4290
4291	4291
4292	4292
4293	4293	HB3779 - 119 - LRB104 11172 AAS 21254 b
4294	4294
4295	4295
4296	4296	HB3779- 120 -LRB104 11172 AAS 21254 b HB3779 - 120 - LRB104 11172 AAS 21254 b
4297	4297	HB3779 - 120 - LRB104 11172 AAS 21254 b
4298	4298	1 to procure renewable energy credits from new and
4299	4299	2 existing hydropower facilities to support the
4300	4300	3 development and maintenance of these facilities. The
4301	4301	4 Agency shall explore options to convert existing dams
4302	4302	5 but shall not consider approaches to develop new dams
4303	4303	6 where they do not already exist.
4304	4304	7 (ii) In any given delivery year, if forecasted
4305	4305	8 expenses are less than the maximum budget available
4306	4306	9 under subparagraph (E) of this paragraph (1), the
4307	4307	10 Agency shall continue to procure new renewable energy
4308	4308	11 credits until that budget is exhausted in the manner
4309	4309	12 outlined in item (i) of this subparagraph (C).
4310	4310	13 (iii) For purposes of this Section:
4311	4311	14 "New wind projects" means wind renewable energy
4312	4312	15 facilities that are energized after June 1, 2017 for
4313	4313	16 the delivery year commencing June 1, 2017.
4314	4314	17 "New photovoltaic projects" means photovoltaic
4315	4315	18 renewable energy facilities that are energized after
4316	4316	19 June 1, 2017. Photovoltaic projects developed under
4317	4317	20 Section 1-56 of this Act shall not apply towards the
4318	4318	21 new photovoltaic project requirements in this
4319	4319	22 subparagraph (C).
4320	4320	23 For purposes of calculating whether the Agency has
4321	4321	24 procured enough new wind and solar renewable energy
4322	4322	25 credits required by this subparagraph (C), renewable
4323	4323	26 energy facilities that have a multi-year renewable
4324	4324
4325	4325
4326	4326
4327	4327
4328	4328
4329	4329	HB3779 - 120 - LRB104 11172 AAS 21254 b
4330	4330
4331	4331
4332	4332	HB3779- 121 -LRB104 11172 AAS 21254 b HB3779 - 121 - LRB104 11172 AAS 21254 b
4333	4333	HB3779 - 121 - LRB104 11172 AAS 21254 b
4334	4334	1 energy credit delivery contract with the utility
4335	4335	2 through at least delivery year 2030 shall be
4336	4336	3 considered new, however no renewable energy credits
4337	4337	4 from contracts entered into before June 1, 2021 shall
4338	4338	5 be used to calculate whether the Agency has procured
4339	4339	6 the correct proportion of new wind and new solar
4340	4340	7 contracts described in this subparagraph (C) for
4341	4341	8 delivery year 2021 and thereafter.
4342	4342	9 (D) Renewable energy credits shall be cost effective.
4343	4343	10 For purposes of this subsection (c), "cost effective"
4344	4344	11 means that the costs of procuring renewable energy
4345	4345	12 resources do not cause the limit stated in subparagraph
4346	4346	13 (E) of this paragraph (1) to be exceeded and, for
4347	4347	14 renewable energy credits procured through a competitive
4348	4348	15 procurement event, do not exceed benchmarks based on
4349	4349	16 market prices for like products in the region. For
4350	4350	17 purposes of this subsection (c), "like products" means
4351	4351	18 contracts for renewable energy credits from the same or
4352	4352	19 substantially similar technology, same or substantially
4353	4353	20 similar vintage (new or existing), the same or
4354	4354	21 substantially similar quantity, and the same or
4355	4355	22 substantially similar contract length and structure.
4356	4356	23 Benchmarks shall reflect development, financing, or
4357	4357	24 related costs resulting from requirements imposed through
4358	4358	25 other provisions of State law, including, but not limited
4359	4359	26 to, requirements in subparagraphs (P) and (Q) of this
4360	4360
4361	4361
4362	4362
4363	4363
4364	4364
4365	4365	HB3779 - 121 - LRB104 11172 AAS 21254 b
4366	4366
4367	4367
4368	4368	HB3779- 122 -LRB104 11172 AAS 21254 b HB3779 - 122 - LRB104 11172 AAS 21254 b
4369	4369	HB3779 - 122 - LRB104 11172 AAS 21254 b
4370	4370	1 paragraph (1) and the Renewable Energy Facilities
4371	4371	2 Agricultural Impact Mitigation Act. Confidential
4372	4372	3 benchmarks shall be developed by the procurement
4373	4373	4 administrator, in consultation with the Commission staff,
4374	4374	5 Agency staff, and the procurement monitor and shall be
4375	4375	6 subject to Commission review and approval. If price
4376	4376	7 benchmarks for like products in the region are not
4377	4377	8 available, the procurement administrator shall establish
4378	4378	9 price benchmarks based on publicly available data on
4379	4379	10 regional technology costs and expected current and future
4380	4380	11 regional energy prices. The benchmarks in this Section
4381	4381	12 shall not be used to curtail or otherwise reduce
4382	4382	13 contractual obligations entered into by or through the
4383	4383	14 Agency prior to June 1, 2017 (the effective date of Public
4384	4384	15 Act 99-906).
4385	4385	16 (E) For purposes of this subsection (c), the required
4386	4386	17 procurement of cost-effective renewable energy resources
4387	4387	18 for a particular year commencing prior to June 1, 2017
4388	4388	19 shall be measured as a percentage of the actual amount of
4389	4389	20 electricity (megawatt-hours) supplied by the electric
4390	4390	21 utility to eligible retail customers in the delivery year
4391	4391	22 ending immediately prior to the procurement, and, for
4392	4392	23 delivery years commencing on and after June 1, 2017, the
4393	4393	24 required procurement of cost-effective renewable energy
4394	4394	25 resources for a particular year shall be measured as a
4395	4395	26 percentage of the actual amount of electricity
4396	4396
4397	4397
4398	4398
4399	4399
4400	4400
4401	4401	HB3779 - 122 - LRB104 11172 AAS 21254 b
4402	4402
4403	4403
4404	4404	HB3779- 123 -LRB104 11172 AAS 21254 b HB3779 - 123 - LRB104 11172 AAS 21254 b
4405	4405	HB3779 - 123 - LRB104 11172 AAS 21254 b
4406	4406	1 (megawatt-hours) delivered by the electric utility in the
4407	4407	2 delivery year ending immediately prior to the procurement,
4408	4408	3 to all retail customers in its service territory. For
4409	4409	4 purposes of this subsection (c), the amount paid per
4410	4410	5 kilowatthour means the total amount paid for electric
4411	4411	6 service expressed on a per kilowatthour basis. For
4412	4412	7 purposes of this subsection (c), the total amount paid for
4413	4413	8 electric service includes without limitation amounts paid
4414	4414	9 for supply, transmission, capacity, distribution,
4415	4415	10 surcharges, and add-on taxes.
4416	4416	11 Notwithstanding the requirements of this subsection
4417	4417	12 (c), the total of renewable energy resources procured
4418	4418	13 under the procurement plan for any single year shall be
4419	4419	14 subject to the limitations of this subparagraph (E).
4420	4420	15 Except as the maximum dollar amount of renewable resources
4421	4421	16 to be procured may be otherwise increased by the
4422	4422	17 Commission in the Agency's long-term renewable resources
4423	4423	18 procurement plan described in subparagraph (A) of this
4424	4424	19 paragraph (1) based on the Commission finding that the
4425	4425	20 expected long-term cost savings to eligible retail
4426	4426	21 customers from the procurements enabled by the increased
4427	4427	22 maximum dollar amount exceed the additional costs, such
4428	4428	23 Such procurement shall be reduced for all retail customers
4429	4429	24 based on the amount necessary to limit the annual
4430	4430	25 estimated average net increase due to the costs of these
4431	4431	26 resources included in the amounts paid by eligible retail
4432	4432
4433	4433
4434	4434
4435	4435
4436	4436
4437	4437	HB3779 - 123 - LRB104 11172 AAS 21254 b
4438	4438
4439	4439
4440	4440	HB3779- 124 -LRB104 11172 AAS 21254 b HB3779 - 124 - LRB104 11172 AAS 21254 b
4441	4441	HB3779 - 124 - LRB104 11172 AAS 21254 b
4442	4442	1 customers in connection with electric service to no more
4443	4443	2 than 4.25% of the amount paid per kilowatthour by those
4444	4444	3 customers during the year ending May 31, 2009. To arrive
4445	4445	4 at a maximum dollar amount of renewable energy resources
4446	4446	5 to be procured for the particular delivery year, the
4447	4447	6 resulting per kilowatthour amount shall be applied to the
4448	4448	7 actual amount of kilowatthours of electricity delivered,
4449	4449	8 or applicable portion of such amount as specified in
4450	4450	9 paragraph (1) of this subsection (c), as applicable, by
4451	4451	10 the electric utility in the delivery year immediately
4452	4452	11 prior to the procurement to all retail customers in its
4453	4453	12 service territory. The calculations required by this
4454	4454	13 subparagraph (E) shall be made only once for each delivery
4455	4455	14 year at the time that the renewable energy resources are
4456	4456	15 procured. Once the determination as to the amount of
4457	4457	16 renewable energy resources to procure is made based on the
4458	4458	17 calculations set forth in this subparagraph (E) and the
4459	4459	18 contracts procuring those amounts are executed, no
4460	4460	19 subsequent rate impact determinations shall be made and no
4461	4461	20 adjustments to those contract amounts shall be allowed.
4462	4462	21 All costs incurred under such contracts shall be fully
4463	4463	22 recoverable by the electric utility as provided in this
4464	4464	23 Section.
4465	4465	24 (F) If the limitation on the amount of renewable
4466	4466	25 energy resources procured in subparagraph (E) of this
4467	4467	26 paragraph (1) prevents the Agency from meeting all of the
4468	4468
4469	4469
4470	4470
4471	4471
4472	4472
4473	4473	HB3779 - 124 - LRB104 11172 AAS 21254 b
4474	4474
4475	4475
4476	4476	HB3779- 125 -LRB104 11172 AAS 21254 b HB3779 - 125 - LRB104 11172 AAS 21254 b
4477	4477	HB3779 - 125 - LRB104 11172 AAS 21254 b
4478	4478	1 goals in this subsection (c), the Agency's long-term plan
4479	4479	2 shall prioritize compliance with the requirements of this
4480	4480	3 subsection (c) regarding renewable energy credits in the
4481	4481	4 following order:
4482	4482	5 (i) renewable energy credits under existing
4483	4483	6 contractual obligations as of June 1, 2021;
4484	4484	7 (i-5) funding for the Illinois Solar for All
4485	4485	8 Program, as described in subparagraph (O) of this
4486	4486	9 paragraph (1);
4487	4487	10 (ii) renewable energy credits necessary to comply
4488	4488	11 with the new wind and new photovoltaic procurement
4489	4489	12 requirements described in items (i) through (iii) of
4490	4490	13 subparagraph (C) of this paragraph (1); and
4491	4491	14 (iii) renewable energy credits necessary to meet
4492	4492	15 the remaining requirements of this subsection (c).
4493	4493	16 (G) The following provisions shall apply to the
4494	4494	17 Agency's procurement of renewable energy credits under
4495	4495	18 this subsection (c):
4496	4496	19 (i) Notwithstanding whether a long-term renewable
4497	4497	20 resources procurement plan has been approved, the
4498	4498	21 Agency shall conduct an initial forward procurement
4499	4499	22 for renewable energy credits from new utility-scale
4500	4500	23 wind projects within 160 days after June 1, 2017 (the
4501	4501	24 effective date of Public Act 99-906). For the purposes
4502	4502	25 of this initial forward procurement, the Agency shall
4503	4503	26 solicit 15-year contracts for delivery of 1,000,000
4504	4504
4505	4505
4506	4506
4507	4507
4508	4508
4509	4509	HB3779 - 125 - LRB104 11172 AAS 21254 b
4510	4510
4511	4511
4512	4512	HB3779- 126 -LRB104 11172 AAS 21254 b HB3779 - 126 - LRB104 11172 AAS 21254 b
4513	4513	HB3779 - 126 - LRB104 11172 AAS 21254 b
4514	4514	1 renewable energy credits delivered annually from new
4515	4515	2 utility-scale wind projects to begin delivery on June
4516	4516	3 1, 2019, if available, but not later than June 1, 2021,
4517	4517	4 unless the project has delays in the establishment of
4518	4518	5 an operating interconnection with the applicable
4519	4519	6 transmission or distribution system as a result of the
4520	4520	7 actions or inactions of the transmission or
4521	4521	8 distribution provider, or other causes for force
4522	4522	9 majeure as outlined in the procurement contract, in
4523	4523	10 which case, not later than June 1, 2022. Payments to
4524	4524	11 suppliers of renewable energy credits shall commence
4525	4525	12 upon delivery. Renewable energy credits procured under
4526	4526	13 this initial procurement shall be included in the
4527	4527	14 Agency's long-term plan and shall apply to all
4528	4528	15 renewable energy goals in this subsection (c).
4529	4529	16 (ii) Notwithstanding whether a long-term renewable
4530	4530	17 resources procurement plan has been approved, the
4531	4531	18 Agency shall conduct an initial forward procurement
4532	4532	19 for renewable energy credits from new utility-scale
4533	4533	20 solar projects and brownfield site photovoltaic
4534	4534	21 projects within one year after June 1, 2017 (the
4535	4535	22 effective date of Public Act 99-906). For the purposes
4536	4536	23 of this initial forward procurement, the Agency shall
4537	4537	24 solicit 15-year contracts for delivery of 1,000,000
4538	4538	25 renewable energy credits delivered annually from new
4539	4539	26 utility-scale solar projects and brownfield site
4540	4540
4541	4541
4542	4542
4543	4543
4544	4544
4545	4545	HB3779 - 126 - LRB104 11172 AAS 21254 b
4546	4546
4547	4547
4548	4548	HB3779- 127 -LRB104 11172 AAS 21254 b HB3779 - 127 - LRB104 11172 AAS 21254 b
4549	4549	HB3779 - 127 - LRB104 11172 AAS 21254 b
4550	4550	1 photovoltaic projects to begin delivery on June 1,
4551	4551	2 2019, if available, but not later than June 1, 2021,
4552	4552	3 unless the project has delays in the establishment of
4553	4553	4 an operating interconnection with the applicable
4554	4554	5 transmission or distribution system as a result of the
4555	4555	6 actions or inactions of the transmission or
4556	4556	7 distribution provider, or other causes for force
4557	4557	8 majeure as outlined in the procurement contract, in
4558	4558	9 which case, not later than June 1, 2022. The Agency may
4559	4559	10 structure this initial procurement in one or more
4560	4560	11 discrete procurement events. Payments to suppliers of
4561	4561	12 renewable energy credits shall commence upon delivery.
4562	4562	13 Renewable energy credits procured under this initial
4563	4563	14 procurement shall be included in the Agency's
4564	4564	15 long-term plan and shall apply to all renewable energy
4565	4565	16 goals in this subsection (c).
4566	4566	17 (iii) Notwithstanding whether the Commission has
4567	4567	18 approved the periodic long-term renewable resources
4568	4568	19 procurement plan revision described in Section
4569	4569	20 16-111.5 of the Public Utilities Act, the Agency shall
4570	4570	21 conduct at least one subsequent forward procurement
4571	4571	22 for renewable energy credits from new utility-scale
4572	4572	23 wind projects, new utility-scale solar projects, and
4573	4573	24 new brownfield site photovoltaic projects within 240
4574	4574	25 days after the effective date of this amendatory Act
4575	4575	26 of the 102nd General Assembly in quantities necessary
4576	4576
4577	4577
4578	4578
4579	4579
4580	4580
4581	4581	HB3779 - 127 - LRB104 11172 AAS 21254 b
4582	4582
4583	4583
4584	4584	HB3779- 128 -LRB104 11172 AAS 21254 b HB3779 - 128 - LRB104 11172 AAS 21254 b
4585	4585	HB3779 - 128 - LRB104 11172 AAS 21254 b
4586	4586	1 to meet the requirements of subparagraph (C) of this
4587	4587	2 paragraph (1) through the delivery year beginning June
4588	4588	3 1, 2021.
4589	4589	4 (iv) Notwithstanding whether the Commission has
4590	4590	5 approved the periodic long-term renewable resources
4591	4591	6 procurement plan revision described in Section
4592	4592	7 16-111.5 of the Public Utilities Act, the Agency shall
4593	4593	8 open capacity for each category in the Adjustable
4594	4594	9 Block program within 90 days after the effective date
4595	4595	10 of this amendatory Act of the 102nd General Assembly
4596	4596	11 manner:
4597	4597	12 (1) The Agency shall open the first block of
4598	4598	13 annual capacity for the category described in item
4599	4599	14 (i) of subparagraph (K) of this paragraph (1). The
4600	4600	15 first block of annual capacity for item (i) shall
4601	4601	16 be for at least 75 megawatts of total nameplate
4602	4602	17 capacity. The price of the renewable energy credit
4603	4603	18 for this block of capacity shall be 4% less than
4604	4604	19 the price of the last open block in this category.
4605	4605	20 Projects on a waitlist shall be awarded contracts
4606	4606	21 first in the order in which they appear on the
4607	4607	22 waitlist. Notwithstanding anything to the
4608	4608	23 contrary, for those renewable energy credits that
4609	4609	24 qualify and are procured under this subitem (1) of
4610	4610	25 this item (iv), the renewable energy credit
4611	4611	26 delivery contract value shall be paid in full,
4612	4612
4613	4613
4614	4614
4615	4615
4616	4616
4617	4617	HB3779 - 128 - LRB104 11172 AAS 21254 b
4618	4618
4619	4619
4620	4620	HB3779- 129 -LRB104 11172 AAS 21254 b HB3779 - 129 - LRB104 11172 AAS 21254 b
4621	4621	HB3779 - 129 - LRB104 11172 AAS 21254 b
4622	4622	1 based on the estimated generation during the first
4623	4623	2 15 years of operation, by the contracting
4624	4624	3 utilities at the time that the facility producing
4625	4625	4 the renewable energy credits is interconnected at
4626	4626	5 the distribution system level of the utility and
4627	4627	6 verified as energized and in compliance by the
4628	4628	7 Program Administrator. The electric utility shall
4629	4629	8 receive and retire all renewable energy credits
4630	4630	9 generated by the project for the first 15 years of
4631	4631	10 operation. Renewable energy credits generated by
4632	4632	11 the project thereafter shall not be transferred
4633	4633	12 under the renewable energy credit delivery
4634	4634	13 contract with the counterparty electric utility.
4635	4635	14 (2) The Agency shall open the first block of
4636	4636	15 annual capacity for the category described in item
4637	4637	16 (ii) of subparagraph (K) of this paragraph (1).
4638	4638	17 The first block of annual capacity for item (ii)
4639	4639	18 shall be for at least 75 megawatts of total
4640	4640	19 nameplate capacity.
4641	4641	20 (A) The price of the renewable energy
4642	4642	21 credit for any project on a waitlist for this
4643	4643	22 category before the opening of this block
4644	4644	23 shall be 4% less than the price of the last
4645	4645	24 open block in this category. Projects on the
4646	4646	25 waitlist shall be awarded contracts first in
4647	4647	26 the order in which they appear on the
4648	4648
4649	4649
4650	4650
4651	4651
4652	4652
4653	4653	HB3779 - 129 - LRB104 11172 AAS 21254 b
4654	4654
4655	4655
4656	4656	HB3779- 130 -LRB104 11172 AAS 21254 b HB3779 - 130 - LRB104 11172 AAS 21254 b
4657	4657	HB3779 - 130 - LRB104 11172 AAS 21254 b
4658	4658	1 waitlist. Any projects that are less than or
4659	4659	2 equal to 25 kilowatts in size on the waitlist
4660	4660	3 for this capacity shall be moved to the
4661	4661	4 waitlist for paragraph (1) of this item (iv).
4662	4662	5 Notwithstanding anything to the contrary,
4663	4663	6 projects that were on the waitlist prior to
4664	4664	7 opening of this block shall not be required to
4665	4665	8 be in compliance with the requirements of
4666	4666	9 subparagraph (Q) of this paragraph (1) of this
4667	4667	10 subsection (c). Notwithstanding anything to
4668	4668	11 the contrary, for those renewable energy
4669	4669	12 credits procured from projects that were on
4670	4670	13 the waitlist for this category before the
4671	4671	14 opening of this block 20% of the renewable
4672	4672	15 energy credit delivery contract value, based
4673	4673	16 on the estimated generation during the first
4674	4674	17 15 years of operation, shall be paid by the
4675	4675	18 contracting utilities at the time that the
4676	4676	19 facility producing the renewable energy
4677	4677	20 credits is interconnected at the distribution
4678	4678	21 system level of the utility and verified as
4679	4679	22 energized by the Program Administrator. The
4680	4680	23 remaining portion shall be paid ratably over
4681	4681	24 the subsequent 4-year period. The electric
4682	4682	25 utility shall receive and retire all renewable
4683	4683	26 energy credits generated by the project during
4684	4684
4685	4685
4686	4686
4687	4687
4688	4688
4689	4689	HB3779 - 130 - LRB104 11172 AAS 21254 b
4690	4690
4691	4691
4692	4692	HB3779- 131 -LRB104 11172 AAS 21254 b HB3779 - 131 - LRB104 11172 AAS 21254 b
4693	4693	HB3779 - 131 - LRB104 11172 AAS 21254 b
4694	4694	1 the first 15 years of operation. Renewable
4695	4695	2 energy credits generated by the project
4696	4696	3 thereafter shall not be transferred under the
4697	4697	4 renewable energy credit delivery contract with
4698	4698	5 the counterparty electric utility.
4699	4699	6 (B) The price of renewable energy credits
4700	4700	7 for any project not on the waitlist for this
4701	4701	8 category before the opening of the block shall
4702	4702	9 be determined and published by the Agency.
4703	4703	10 Projects not on a waitlist as of the opening
4704	4704	11 of this block shall be subject to the
4705	4705	12 requirements of subparagraph (Q) of this
4706	4706	13 paragraph (1), as applicable. Projects not on
4707	4707	14 a waitlist as of the opening of this block
4708	4708	15 shall be subject to the contract provisions
4709	4709	16 outlined in item (iii) of subparagraph (L) of
4710	4710	17 this paragraph (1). The Agency shall strive to
4711	4711	18 publish updated prices and an updated
4712	4712	19 renewable energy credit delivery contract as
4713	4713	20 quickly as possible.
4714	4714	21 (3) For opening the first 2 blocks of annual
4715	4715	22 capacity for projects participating in item (iii)
4716	4716	23 of subparagraph (K) of paragraph (1) of subsection
4717	4717	24 (c), projects shall be selected exclusively from
4718	4718	25 those projects on the ordinal waitlists of
4719	4719	26 community renewable generation projects
4720	4720
4721	4721
4722	4722
4723	4723
4724	4724
4725	4725	HB3779 - 131 - LRB104 11172 AAS 21254 b
4726	4726
4727	4727
4728	4728	HB3779- 132 -LRB104 11172 AAS 21254 b HB3779 - 132 - LRB104 11172 AAS 21254 b
4729	4729	HB3779 - 132 - LRB104 11172 AAS 21254 b
4730	4730	1 established by the Agency based on the status of
4731	4731	2 those ordinal waitlists as of December 31, 2020,
4732	4732	3 and only those projects previously determined to
4733	4733	4 be eligible for the Agency's April 2019 community
4734	4734	5 solar project selection process.
4735	4735	6 The first 2 blocks of annual capacity for item
4736	4736	7 (iii) shall be for 250 megawatts of total
4737	4737	8 nameplate capacity, with both blocks opening
4738	4738	9 simultaneously under the schedule outlined in the
4739	4739	10 paragraphs below. Projects shall be selected as
4740	4740	11 follows:
4741	4741	12 (A) The geographic balance of selected
4742	4742	13 projects shall follow the Group classification
4743	4743	14 found in the Agency's Revised Long-Term
4744	4744	15 Renewable Resources Procurement Plan, with 70%
4745	4745	16 of capacity allocated to projects on the Group
4746	4746	17 B waitlist and 30% of capacity allocated to
4747	4747	18 projects on the Group A waitlist.
4748	4748	19 (B) Contract awards for waitlisted
4749	4749	20 projects shall be allocated proportionate to
4750	4750	21 the total nameplate capacity amount across
4751	4751	22 both ordinal waitlists associated with that
4752	4752	23 applicant firm or its affiliates, subject to
4753	4753	24 the following conditions.
4754	4754	25 (i) Each applicant firm having a
4755	4755	26 waitlisted project eligible for selection
4756	4756
4757	4757
4758	4758
4759	4759
4760	4760
4761	4761	HB3779 - 132 - LRB104 11172 AAS 21254 b
4762	4762
4763	4763
4764	4764	HB3779- 133 -LRB104 11172 AAS 21254 b HB3779 - 133 - LRB104 11172 AAS 21254 b
4765	4765	HB3779 - 133 - LRB104 11172 AAS 21254 b
4766	4766	1 shall receive no less than 500 kilowatts
4767	4767	2 in awarded capacity across all groups, and
4768	4768	3 no approved vendor may receive more than
4769	4769	4 20% of each Group's waitlist allocation.
4770	4770	5 (ii) Each applicant firm, upon
4771	4771	6 receiving an award of program capacity
4772	4772	7 proportionate to its waitlisted capacity,
4773	4773	8 may then determine which waitlisted
4774	4774	9 projects it chooses to be selected for a
4775	4775	10 contract award up to that capacity amount.
4776	4776	11 (iii) Assuming all other program
4777	4777	12 requirements are met, applicant firms may
4778	4778	13 adjust the nameplate capacity of applicant
4779	4779	14 projects without losing waitlist
4780	4780	15 eligibility, so long as no project is
4781	4781	16 greater than 2,000 kilowatts in size.
4782	4782	17 (iv) Assuming all other program
4783	4783	18 requirements are met, applicant firms may
4784	4784	19 adjust the expected production associated
4785	4785	20 with applicant projects, subject to
4786	4786	21 verification by the Program Administrator.
4787	4787	22 (C) After a review of affiliate
4788	4788	23 information and the current ordinal waitlists,
4789	4789	24 the Agency shall announce the nameplate
4790	4790	25 capacity award amounts associated with
4791	4791	26 applicant firms no later than 90 days after
4792	4792
4793	4793
4794	4794
4795	4795
4796	4796
4797	4797	HB3779 - 133 - LRB104 11172 AAS 21254 b
4798	4798
4799	4799
4800	4800	HB3779- 134 -LRB104 11172 AAS 21254 b HB3779 - 134 - LRB104 11172 AAS 21254 b
4801	4801	HB3779 - 134 - LRB104 11172 AAS 21254 b
4802	4802	1 the effective date of this amendatory Act of
4803	4803	2 the 102nd General Assembly.
4804	4804	3 (D) Applicant firms shall submit their
4805	4805	4 portfolio of projects used to satisfy those
4806	4806	5 contract awards no less than 90 days after the
4807	4807	6 Agency's announcement. The total nameplate
4808	4808	7 capacity of all projects used to satisfy that
4809	4809	8 portfolio shall be no greater than the
4810	4810	9 Agency's nameplate capacity award amount
4811	4811	10 associated with that applicant firm. An
4812	4812	11 applicant firm may decline, in whole or in
4813	4813	12 part, its nameplate capacity award without
4814	4814	13 penalty, with such unmet capacity rolled over
4815	4815	14 to the next block opening for project
4816	4816	15 selection under item (iii) of subparagraph (K)
4817	4817	16 of this subsection (c). Any projects not
4818	4818	17 included in an applicant firm's portfolio may
4819	4819	18 reapply without prejudice upon the next block
4820	4820	19 reopening for project selection under item
4821	4821	20 (iii) of subparagraph (K) of this subsection
4822	4822	21 (c).
4823	4823	22 (E) The renewable energy credit delivery
4824	4824	23 contract shall be subject to the contract and
4825	4825	24 payment terms outlined in item (iv) of
4826	4826	25 subparagraph (L) of this subsection (c).
4827	4827	26 Contract instruments used for this
4828	4828
4829	4829
4830	4830
4831	4831
4832	4832
4833	4833	HB3779 - 134 - LRB104 11172 AAS 21254 b
4834	4834
4835	4835
4836	4836	HB3779- 135 -LRB104 11172 AAS 21254 b HB3779 - 135 - LRB104 11172 AAS 21254 b
4837	4837	HB3779 - 135 - LRB104 11172 AAS 21254 b
4838	4838	1 subparagraph shall contain the following
4839	4839	2 terms:
4840	4840	3 (i) Renewable energy credit prices
4841	4841	4 shall be fixed, without further adjustment
4842	4842	5 under any other provision of this Act or
4843	4843	6 for any other reason, at 10% lower than
4844	4844	7 prices applicable to the last open block
4845	4845	8 for this category, inclusive of any adders
4846	4846	9 available for achieving a minimum of 50%
4847	4847	10 of subscribers to the project's nameplate
4848	4848	11 capacity being residential or small
4849	4849	12 commercial customers with subscriptions of
4850	4850	13 below 25 kilowatts in size;
4851	4851	14 (ii) A requirement that a minimum of
4852	4852	15 50% of subscribers to the project's
4853	4853	16 nameplate capacity be residential or small
4854	4854	17 commercial customers with subscriptions of
4855	4855	18 below 25 kilowatts in size;
4856	4856	19 (iii) Permission for the ability of a
4857	4857	20 contract holder to substitute projects
4858	4858	21 with other waitlisted projects without
4859	4859	22 penalty should a project receive a
4860	4860	23 non-binding estimate of costs to construct
4861	4861	24 the interconnection facilities and any
4862	4862	25 required distribution upgrades associated
4863	4863	26 with that project of greater than 30 cents
4864	4864
4865	4865
4866	4866
4867	4867
4868	4868
4869	4869	HB3779 - 135 - LRB104 11172 AAS 21254 b
4870	4870
4871	4871
4872	4872	HB3779- 136 -LRB104 11172 AAS 21254 b HB3779 - 136 - LRB104 11172 AAS 21254 b
4873	4873	HB3779 - 136 - LRB104 11172 AAS 21254 b
4874	4874	1 per watt AC of that project's nameplate
4875	4875	2 capacity. In developing the applicable
4876	4876	3 contract instrument, the Agency may
4877	4877	4 consider whether other circumstances
4878	4878	5 outside of the control of the applicant
4879	4879	6 firm should also warrant project
4880	4880	7 substitution rights.
4881	4881	8 The Agency shall publish a finalized
4882	4882	9 updated renewable energy credit delivery
4883	4883	10 contract developed consistent with these terms
4884	4884	11 and conditions no less than 30 days before
4885	4885	12 applicant firms must submit their portfolio of
4886	4886	13 projects pursuant to item (D).
4887	4887	14 (F) To be eligible for an award, the
4888	4888	15 applicant firm shall certify that not less
4889	4889	16 than prevailing wage, as determined pursuant
4890	4890	17 to the Illinois Prevailing Wage Act, was or
4891	4891	18 will be paid to employees who are engaged in
4892	4892	19 construction activities associated with a
4893	4893	20 selected project.
4894	4894	21 (4) The Agency shall open the first block of
4895	4895	22 annual capacity for the category described in item
4896	4896	23 (iv) of subparagraph (K) of this paragraph (1).
4897	4897	24 The first block of annual capacity for item (iv)
4898	4898	25 shall be for at least 50 megawatts of total
4899	4899	26 nameplate capacity. Renewable energy credit prices
4900	4900
4901	4901
4902	4902
4903	4903
4904	4904
4905	4905	HB3779 - 136 - LRB104 11172 AAS 21254 b
4906	4906
4907	4907
4908	4908	HB3779- 137 -LRB104 11172 AAS 21254 b HB3779 - 137 - LRB104 11172 AAS 21254 b
4909	4909	HB3779 - 137 - LRB104 11172 AAS 21254 b
4910	4910	1 shall be fixed, without further adjustment under
4911	4911	2 any other provision of this Act or for any other
4912	4912	3 reason, at the price in the last open block in the
4913	4913	4 category described in item (ii) of subparagraph
4914	4914	5 (K) of this paragraph (1). Pricing for future
4915	4915	6 blocks of annual capacity for this category may be
4916	4916	7 adjusted in the Agency's second revision to its
4917	4917	8 Long-Term Renewable Resources Procurement Plan.
4918	4918	9 Projects in this category shall be subject to the
4919	4919	10 contract terms outlined in item (iv) of
4920	4920	11 subparagraph (L) of this paragraph (1).
4921	4921	12 (5) The Agency shall open the equivalent of 2
4922	4922	13 years of annual capacity for the category
4923	4923	14 described in item (v) of subparagraph (K) of this
4924	4924	15 paragraph (1). The first block of annual capacity
4925	4925	16 for item (v) shall be for at least 10 megawatts of
4926	4926	17 total nameplate capacity. Notwithstanding the
4927	4927	18 provisions of item (v) of subparagraph (K) of this
4928	4928	19 paragraph (1), for the purpose of this initial
4929	4929	20 block, the agency shall accept new project
4930	4930	21 applications intended to increase the diversity of
4931	4931	22 areas hosting community solar projects, the
4932	4932	23 business models of projects, and the size of
4933	4933	24 projects, as described by the Agency in its
4934	4934	25 long-term renewable resources procurement plan
4935	4935	26 that is approved as of the effective date of this
4936	4936
4937	4937
4938	4938
4939	4939
4940	4940
4941	4941	HB3779 - 137 - LRB104 11172 AAS 21254 b
4942	4942
4943	4943
4944	4944	HB3779- 138 -LRB104 11172 AAS 21254 b HB3779 - 138 - LRB104 11172 AAS 21254 b
4945	4945	HB3779 - 138 - LRB104 11172 AAS 21254 b
4946	4946	1 amendatory Act of the 102nd General Assembly.
4947	4947	2 Projects in this category shall be subject to the
4948	4948	3 contract terms outlined in item (iii) of
4949	4949	4 subsection (L) of this paragraph (1).
4950	4950	5 (6) The Agency shall open the first blocks of
4951	4951	6 annual capacity for the category described in item
4952	4952	7 (vi) of subparagraph (K) of this paragraph (1),
4953	4953	8 with allocations of capacity within the block
4954	4954	9 generally matching the historical share of block
4955	4955	10 capacity allocated between the category described
4956	4956	11 in items (i) and (ii) of subparagraph (K) of this
4957	4957	12 paragraph (1). The first two blocks of annual
4958	4958	13 capacity for item (vi) shall be for at least 75
4959	4959	14 megawatts of total nameplate capacity. The price
4960	4960	15 of renewable energy credits for the blocks of
4961	4961	16 capacity shall be 4% less than the price of the
4962	4962	17 last open blocks in the categories described in
4963	4963	18 items (i) and (ii) of subparagraph (K) of this
4964	4964	19 paragraph (1). Pricing for future blocks of annual
4965	4965	20 capacity for this category may be adjusted in the
4966	4966	21 Agency's second revision to its Long-Term
4967	4967	22 Renewable Resources Procurement Plan. Projects in
4968	4968	23 this category shall be subject to the applicable
4969	4969	24 contract terms outlined in items (ii) and (iii) of
4970	4970	25 subparagraph (L) of this paragraph (1).
4971	4971	26 (v) Upon the effective date of this amendatory Act
4972	4972
4973	4973
4974	4974
4975	4975
4976	4976
4977	4977	HB3779 - 138 - LRB104 11172 AAS 21254 b
4978	4978
4979	4979
4980	4980	HB3779- 139 -LRB104 11172 AAS 21254 b HB3779 - 139 - LRB104 11172 AAS 21254 b
4981	4981	HB3779 - 139 - LRB104 11172 AAS 21254 b
4982	4982	1 of the 102nd General Assembly, for all competitive
4983	4983	2 procurements and any procurements of renewable energy
4984	4984	3 credit from new utility-scale wind and new
4985	4985	4 utility-scale photovoltaic projects, the Agency shall
4986	4986	5 procure indexed renewable energy credits and direct
4987	4987	6 respondents to offer a strike price.
4988	4988	7 (1) The purchase price of the indexed
4989	4989	8 renewable energy credit payment shall be
4990	4990	9 calculated for each settlement period. That
4991	4991	10 payment, for any settlement period, shall be equal
4992	4992	11 to the difference resulting from subtracting the
4993	4993	12 strike price from the index price for that
4994	4994	13 settlement period. If this difference results in a
4995	4995	14 negative number, the indexed REC counterparty
4996	4996	15 shall owe the seller the absolute value multiplied
4997	4997	16 by the quantity of energy produced in the relevant
4998	4998	17 settlement period. If this difference results in a
4999	4999	18 positive number, the seller shall owe the indexed
5000	5000	19 REC counterparty this amount multiplied by the
5001	5001	20 quantity of energy produced in the relevant
5002	5002	21 settlement period.
5003	5003	22 (2) Parties shall cash settle every month,
5004	5004	23 summing up all settlements (both positive and
5005	5005	24 negative, if applicable) for the prior month.
5006	5006	25 (3) To ensure funding in the annual budget
5007	5007	26 established under subparagraph (E) for indexed
5008	5008
5009	5009
5010	5010
5011	5011
5012	5012
5013	5013	HB3779 - 139 - LRB104 11172 AAS 21254 b
5014	5014
5015	5015
5016	5016	HB3779- 140 -LRB104 11172 AAS 21254 b HB3779 - 140 - LRB104 11172 AAS 21254 b
5017	5017	HB3779 - 140 - LRB104 11172 AAS 21254 b
5018	5018	1 renewable energy credit procurements for each year
5019	5019	2 of the term of such contracts, which must have a
5020	5020	3 minimum tenure of 20 calendar years, the
5021	5021	4 procurement administrator, Agency, Commission
5022	5022	5 staff, and procurement monitor shall quantify the
5023	5023	6 annual cost of the contract by utilizing an
5024	5024	7 industry-standard, third-party forward price curve
5025	5025	8 for energy at the appropriate hub or load zone,
5026	5026	9 including the estimated magnitude and timing of
5027	5027	10 the price effects related to federal carbon
5028	5028	11 controls. Each forward price curve shall contain a
5029	5029	12 specific value of the forecasted market price of
5030	5030	13 electricity for each annual delivery year of the
5031	5031	14 contract. For procurement planning purposes, the
5032	5032	15 impact on the annual budget for the cost of
5033	5033	16 indexed renewable energy credits for each delivery
5034	5034	17 year shall be determined as the expected annual
5035	5035	18 contract expenditure for that year, equaling the
5036	5036	19 difference between (i) the sum across all relevant
5037	5037	20 contracts of the applicable strike price
5038	5038	21 multiplied by contract quantity and (ii) the sum
5039	5039	22 across all relevant contracts of the forward price
5040	5040	23 curve for the applicable load zone for that year
5041	5041	24 multiplied by contract quantity. The contracting
5042	5042	25 utility shall not assume an obligation in excess
5043	5043	26 of the estimated annual cost of the contracts for
5044	5044
5045	5045
5046	5046
5047	5047
5048	5048
5049	5049	HB3779 - 140 - LRB104 11172 AAS 21254 b
5050	5050
5051	5051
5052	5052	HB3779- 141 -LRB104 11172 AAS 21254 b HB3779 - 141 - LRB104 11172 AAS 21254 b
5053	5053	HB3779 - 141 - LRB104 11172 AAS 21254 b
5054	5054	1 indexed renewable energy credits. Forward curves
5055	5055	2 shall be revised on an annual basis as updated
5056	5056	3 forward price curves are released and filed with
5057	5057	4 the Commission in the proceeding approving the
5058	5058	5 Agency's most recent long-term renewable resources
5059	5059	6 procurement plan. If the expected contract spend
5060	5060	7 is higher or lower than the total quantity of
5061	5061	8 contracts multiplied by the forward price curve
5062	5062	9 value for that year, the forward price curve shall
5063	5063	10 be updated by the procurement administrator, in
5064	5064	11 consultation with the Agency, Commission staff,
5065	5065	12 and procurement monitors, using then-currently
5066	5066	13 available price forecast data and additional
5067	5067	14 budget dollars shall be obligated or reobligated
5068	5068	15 as appropriate.
5069	5069	16 (4) To ensure that indexed renewable energy
5070	5070	17 credit prices remain predictable and affordable,
5071	5071	18 the Agency may consider the institution of a price
5072	5072	19 collar on REC prices paid under indexed renewable
5073	5073	20 energy credit procurements establishing floor and
5074	5074	21 ceiling REC prices applicable to indexed REC
5075	5075	22 contract prices. Any price collars applicable to
5076	5076	23 indexed REC procurements shall be proposed by the
5077	5077	24 Agency through its long-term renewable resources
5078	5078	25 procurement plan.
5079	5079	26 (vi) All procurements under this subparagraph (G),
5080	5080
5081	5081
5082	5082
5083	5083
5084	5084
5085	5085	HB3779 - 141 - LRB104 11172 AAS 21254 b
5086	5086
5087	5087
5088	5088	HB3779- 142 -LRB104 11172 AAS 21254 b HB3779 - 142 - LRB104 11172 AAS 21254 b
5089	5089	HB3779 - 142 - LRB104 11172 AAS 21254 b
5090	5090	1 including the procurement of renewable energy credits
5091	5091	2 from hydropower facilities, shall comply with the
5092	5092	3 geographic requirements in subparagraph (I) of this
5093	5093	4 paragraph (1) and shall follow the procurement
5094	5094	5 processes and procedures described in this Section and
5095	5095	6 Section 16-111.5 of the Public Utilities Act to the
5096	5096	7 extent practicable, and these processes and procedures
5097	5097	8 may be expedited to accommodate the schedule
5098	5098	9 established by this subparagraph (G).
5099	5099	10 (vii) On and after the effective date of this
5100	5100	11 amendatory Act of the 103rd General Assembly, for all
5101	5101	12 procurements of renewable energy credits from
5102	5102	13 hydropower facilities, the Agency shall establish
5103	5103	14 contract terms designed to optimize existing
5104	5104	15 hydropower facilities through modernization or
5105	5105	16 retooling and establish new hydropower facilities at
5106	5106	17 existing dams. Procurements made under this item (vii)
5107	5107	18 shall prioritize projects located in designated
5108	5108	19 environmental justice communities, as defined in
5109	5109	20 subsection (b) of Section 1-56 of this Act, or in
5110	5110	21 projects located in units of local government with
5111	5111	22 median incomes that do not exceed 82% of the median
5112	5112	23 income of the State.
5113	5113	24 (H) The procurement of renewable energy resources for
5114	5114	25 a given delivery year shall be reduced as described in
5115	5115	26 this subparagraph (H) if an alternative retail electric
5116	5116
5117	5117
5118	5118
5119	5119
5120	5120
5121	5121	HB3779 - 142 - LRB104 11172 AAS 21254 b
5122	5122
5123	5123
5124	5124	HB3779- 143 -LRB104 11172 AAS 21254 b HB3779 - 143 - LRB104 11172 AAS 21254 b
5125	5125	HB3779 - 143 - LRB104 11172 AAS 21254 b
5126	5126	1 supplier meets the requirements described in this
5127	5127	2 subparagraph (H).
5128	5128	3 (i) Within 45 days after June 1, 2017 (the
5129	5129	4 effective date of Public Act 99-906), an alternative
5130	5130	5 retail electric supplier or its successor shall submit
5131	5131	6 an informational filing to the Illinois Commerce
5132	5132	7 Commission certifying that, as of December 31, 2015,
5133	5133	8 the alternative retail electric supplier owned one or
5134	5134	9 more electric generating facilities that generates
5135	5135	10 renewable energy resources as defined in Section 1-10
5136	5136	11 of this Act, provided that such facilities are not
5137	5137	12 powered by wind or photovoltaics, and the facilities
5138	5138	13 generate one renewable energy credit for each
5139	5139	14 megawatthour of energy produced from the facility.
5140	5140	15 The informational filing shall identify each
5141	5141	16 facility that was eligible to satisfy the alternative
5142	5142	17 retail electric supplier's obligations under Section
5143	5143	18 16-115D of the Public Utilities Act as described in
5144	5144	19 this item (i).
5145	5145	20 (ii) For a given delivery year, the alternative
5146	5146	21 retail electric supplier may elect to supply its
5147	5147	22 retail customers with renewable energy credits from
5148	5148	23 the facility or facilities described in item (i) of
5149	5149	24 this subparagraph (H) that continue to be owned by the
5150	5150	25 alternative retail electric supplier.
5151	5151	26 (iii) The alternative retail electric supplier
5152	5152
5153	5153
5154	5154
5155	5155
5156	5156
5157	5157	HB3779 - 143 - LRB104 11172 AAS 21254 b
5158	5158
5159	5159
5160	5160	HB3779- 144 -LRB104 11172 AAS 21254 b HB3779 - 144 - LRB104 11172 AAS 21254 b
5161	5161	HB3779 - 144 - LRB104 11172 AAS 21254 b
5162	5162	1 shall notify the Agency and the applicable utility, no
5163	5163	2 later than February 28 of the year preceding the
5164	5164	3 applicable delivery year or 15 days after June 1, 2017
5165	5165	4 (the effective date of Public Act 99-906), whichever
5166	5166	5 is later, of its election under item (ii) of this
5167	5167	6 subparagraph (H) to supply renewable energy credits to
5168	5168	7 retail customers of the utility. Such election shall
5169	5169	8 identify the amount of renewable energy credits to be
5170	5170	9 supplied by the alternative retail electric supplier
5171	5171	10 to the utility's retail customers and the source of
5172	5172	11 the renewable energy credits identified in the
5173	5173	12 informational filing as described in item (i) of this
5174	5174	13 subparagraph (H), subject to the following
5175	5175	14 limitations:
5176	5176	15 For the delivery year beginning June 1, 2018,
5177	5177	16 the maximum amount of renewable energy credits to
5178	5178	17 be supplied by an alternative retail electric
5179	5179	18 supplier under this subparagraph (H) shall be 68%
5180	5180	19 multiplied by 25% multiplied by 14.5% multiplied
5181	5181	20 by the amount of metered electricity
5182	5182	21 (megawatt-hours) delivered by the alternative
5183	5183	22 retail electric supplier to Illinois retail
5184	5184	23 customers during the delivery year ending May 31,
5185	5185	24 2016.
5186	5186	25 For delivery years beginning June 1, 2019 and
5187	5187	26 each year thereafter, the maximum amount of
5188	5188
5189	5189
5190	5190
5191	5191
5192	5192
5193	5193	HB3779 - 144 - LRB104 11172 AAS 21254 b
5194	5194
5195	5195
5196	5196	HB3779- 145 -LRB104 11172 AAS 21254 b HB3779 - 145 - LRB104 11172 AAS 21254 b
5197	5197	HB3779 - 145 - LRB104 11172 AAS 21254 b
5198	5198	1 renewable energy credits to be supplied by an
5199	5199	2 alternative retail electric supplier under this
5200	5200	3 subparagraph (H) shall be 68% multiplied by 50%
5201	5201	4 multiplied by 16% multiplied by the amount of
5202	5202	5 metered electricity (megawatt-hours) delivered by
5203	5203	6 the alternative retail electric supplier to
5204	5204	7 Illinois retail customers during the delivery year
5205	5205	8 ending May 31, 2016, provided that the 16% value
5206	5206	9 shall increase by 1.5% each delivery year
5207	5207	10 thereafter to 25% by the delivery year beginning
5208	5208	11 June 1, 2025, and thereafter the 25% value shall
5209	5209	12 apply to each delivery year.
5210	5210	13 For each delivery year, the total amount of
5211	5211	14 renewable energy credits supplied by all alternative
5212	5212	15 retail electric suppliers under this subparagraph (H)
5213	5213	16 shall not exceed 9% of the Illinois target renewable
5214	5214	17 energy credit quantity. The Illinois target renewable
5215	5215	18 energy credit quantity for the delivery year beginning
5216	5216	19 June 1, 2018 is 14.5% multiplied by the total amount of
5217	5217	20 metered electricity (megawatt-hours) delivered in the
5218	5218	21 delivery year immediately preceding that delivery
5219	5219	22 year, provided that the 14.5% shall increase by 1.5%
5220	5220	23 each delivery year thereafter to 25% by the delivery
5221	5221	24 year beginning June 1, 2025, and thereafter the 25%
5222	5222	25 value shall apply to each delivery year.
5223	5223	26 If the requirements set forth in items (i) through
5224	5224
5225	5225
5226	5226
5227	5227
5228	5228
5229	5229	HB3779 - 145 - LRB104 11172 AAS 21254 b
5230	5230
5231	5231
5232	5232	HB3779- 146 -LRB104 11172 AAS 21254 b HB3779 - 146 - LRB104 11172 AAS 21254 b
5233	5233	HB3779 - 146 - LRB104 11172 AAS 21254 b
5234	5234	1 (iii) of this subparagraph (H) are met, the charges
5235	5235	2 that would otherwise be applicable to the retail
5236	5236	3 customers of the alternative retail electric supplier
5237	5237	4 under paragraph (6) of this subsection (c) for the
5238	5238	5 applicable delivery year shall be reduced by the ratio
5239	5239	6 of the quantity of renewable energy credits supplied
5240	5240	7 by the alternative retail electric supplier compared
5241	5241	8 to that supplier's target renewable energy credit
5242	5242	9 quantity. The supplier's target renewable energy
5243	5243	10 credit quantity for the delivery year beginning June
5244	5244	11 1, 2018 is 14.5% multiplied by the total amount of
5245	5245	12 metered electricity (megawatt-hours) delivered by the
5246	5246	13 alternative retail supplier in that delivery year,
5247	5247	14 provided that the 14.5% shall increase by 1.5% each
5248	5248	15 delivery year thereafter to 25% by the delivery year
5249	5249	16 beginning June 1, 2025, and thereafter the 25% value
5250	5250	17 shall apply to each delivery year.
5251	5251	18 On or before April 1 of each year, the Agency shall
5252	5252	19 annually publish a report on its website that
5253	5253	20 identifies the aggregate amount of renewable energy
5254	5254	21 credits supplied by alternative retail electric
5255	5255	22 suppliers under this subparagraph (H).
5256	5256	23 (I) The Agency shall design its long-term renewable
5257	5257	24 energy procurement plan to maximize the State's interest
5258	5258	25 in the health, safety, and welfare of its residents,
5259	5259	26 including but not limited to minimizing sulfur dioxide,
5260	5260
5261	5261
5262	5262
5263	5263
5264	5264
5265	5265	HB3779 - 146 - LRB104 11172 AAS 21254 b
5266	5266
5267	5267
5268	5268	HB3779- 147 -LRB104 11172 AAS 21254 b HB3779 - 147 - LRB104 11172 AAS 21254 b
5269	5269	HB3779 - 147 - LRB104 11172 AAS 21254 b
5270	5270	1 nitrogen oxide, particulate matter and other pollution
5271	5271	2 that adversely affects public health in this State,
5272	5272	3 increasing fuel and resource diversity in this State,
5273	5273	4 enhancing the reliability and resiliency of the
5274	5274	5 electricity distribution system in this State, meeting
5275	5275	6 goals to limit carbon dioxide emissions under federal or
5276	5276	7 State law, and contributing to a cleaner and healthier
5277	5277	8 environment for the citizens of this State. In order to
5278	5278	9 further these legislative purposes, renewable energy
5279	5279	10 credits shall be eligible to be counted toward the
5280	5280	11 renewable energy requirements of this subsection (c) if
5281	5281	12 they are generated from facilities located in this State.
5282	5282	13 The Agency may qualify renewable energy credits from
5283	5283	14 facilities located in states adjacent to Illinois or
5284	5284	15 renewable energy credits associated with the electricity
5285	5285	16 generated by a utility-scale wind energy facility or
5286	5286	17 utility-scale photovoltaic facility and transmitted by a
5287	5287	18 qualifying direct current project described in subsection
5288	5288	19 (b-5) of Section 8-406 of the Public Utilities Act to a
5289	5289	20 delivery point on the electric transmission grid located
5290	5290	21 in this State or a state adjacent to Illinois, if the
5291	5291	22 generator demonstrates and the Agency determines that the
5292	5292	23 operation of such facility or facilities will help promote
5293	5293	24 the State's interest in the health, safety, and welfare of
5294	5294	25 its residents based on the public interest criteria
5295	5295	26 described above. For the purposes of this Section,
5296	5296
5297	5297
5298	5298
5299	5299
5300	5300
5301	5301	HB3779 - 147 - LRB104 11172 AAS 21254 b
5302	5302
5303	5303
5304	5304	HB3779- 148 -LRB104 11172 AAS 21254 b HB3779 - 148 - LRB104 11172 AAS 21254 b
5305	5305	HB3779 - 148 - LRB104 11172 AAS 21254 b
5306	5306	1 renewable resources that are delivered via a high voltage
5307	5307	2 direct current converter station located in Illinois shall
5308	5308	3 be deemed generated in Illinois at the time and location
5309	5309	4 the energy is converted to alternating current by the high
5310	5310	5 voltage direct current converter station if the high
5311	5311	6 voltage direct current transmission line: (i) after the
5312	5312	7 effective date of this amendatory Act of the 102nd General
5313	5313	8 Assembly, was constructed with a project labor agreement;
5314	5314	9 (ii) is capable of transmitting electricity at 525kv;
5315	5315	10 (iii) has an Illinois converter station located and
5316	5316	11 interconnected in the region of the PJM Interconnection,
5317	5317	12 LLC; (iv) does not operate as a public utility; and (v) if
5318	5318	13 the high voltage direct current transmission line was
5319	5319	14 energized after June 1, 2023. To ensure that the public
5320	5320	15 interest criteria are applied to the procurement and given
5321	5321	16 full effect, the Agency's long-term procurement plan shall
5322	5322	17 describe in detail how each public interest factor shall
5323	5323	18 be considered and weighted for facilities located in
5324	5324	19 states adjacent to Illinois.
5325	5325	20 (J) In order to promote the competitive development of
5326	5326	21 renewable energy resources in furtherance of the State's
5327	5327	22 interest in the health, safety, and welfare of its
5328	5328	23 residents, renewable energy credits shall not be eligible
5329	5329	24 to be counted toward the renewable energy requirements of
5330	5330	25 this subsection (c) if they are sourced from a generating
5331	5331	26 unit whose costs were being recovered through rates
5332	5332
5333	5333
5334	5334
5335	5335
5336	5336
5337	5337	HB3779 - 148 - LRB104 11172 AAS 21254 b
5338	5338
5339	5339
5340	5340	HB3779- 149 -LRB104 11172 AAS 21254 b HB3779 - 149 - LRB104 11172 AAS 21254 b
5341	5341	HB3779 - 149 - LRB104 11172 AAS 21254 b
5342	5342	1 regulated by this State or any other state or states on or
5343	5343	2 after January 1, 2017. Each contract executed to purchase
5344	5344	3 renewable energy credits under this subsection (c) shall
5345	5345	4 provide for the contract's termination if the costs of the
5346	5346	5 generating unit supplying the renewable energy credits
5347	5347	6 subsequently begin to be recovered through rates regulated
5348	5348	7 by this State or any other state or states; and each
5349	5349	8 contract shall further provide that, in that event, the
5350	5350	9 supplier of the credits must return 110% of all payments
5351	5351	10 received under the contract. Amounts returned under the
5352	5352	11 requirements of this subparagraph (J) shall be retained by
5353	5353	12 the utility and all of these amounts shall be used for the
5354	5354	13 procurement of additional renewable energy credits from
5355	5355	14 new wind or new photovoltaic resources as defined in this
5356	5356	15 subsection (c). The long-term plan shall provide that
5357	5357	16 these renewable energy credits shall be procured in the
5358	5358	17 next procurement event.
5359	5359	18 Notwithstanding the limitations of this subparagraph
5360	5360	19 (J), renewable energy credits sourced from generating
5361	5361	20 units that are constructed, purchased, owned, or leased by
5362	5362	21 an electric utility as part of an approved project,
5363	5363	22 program, or pilot under Section 1-56 of this Act shall be
5364	5364	23 eligible to be counted toward the renewable energy
5365	5365	24 requirements of this subsection (c), regardless of how the
5366	5366	25 costs of these units are recovered. As long as a
5367	5367	26 generating unit or an identifiable portion of a generating
5368	5368
5369	5369
5370	5370
5371	5371
5372	5372
5373	5373	HB3779 - 149 - LRB104 11172 AAS 21254 b
5374	5374
5375	5375
5376	5376	HB3779- 150 -LRB104 11172 AAS 21254 b HB3779 - 150 - LRB104 11172 AAS 21254 b
5377	5377	HB3779 - 150 - LRB104 11172 AAS 21254 b
5378	5378	1 unit has not had and does not have its costs recovered
5379	5379	2 through rates regulated by this State or any other state,
5380	5380	3 HVDC renewable energy credits associated with that
5381	5381	4 generating unit or identifiable portion thereof shall be
5382	5382	5 eligible to be counted toward the renewable energy
5383	5383	6 requirements of this subsection (c).
5384	5384	7 (K) The long-term renewable resources procurement plan
5385	5385	8 developed by the Agency in accordance with subparagraph
5386	5386	9 (A) of this paragraph (1) shall include an Adjustable
5387	5387	10 Block program for the procurement of renewable energy
5388	5388	11 credits from new photovoltaic projects that are
5389	5389	12 distributed renewable energy generation devices or new
5390	5390	13 photovoltaic community renewable generation projects. The
5391	5391	14 Adjustable Block program shall be generally designed to
5392	5392	15 provide for the steady, predictable, and sustainable
5393	5393	16 growth of new solar photovoltaic development in Illinois.
5394	5394	17 To this end, the Adjustable Block program shall provide a
5395	5395	18 transparent annual schedule of prices and quantities to
5396	5396	19 enable the photovoltaic market to scale up and for
5397	5397	20 renewable energy credit prices to adjust at a predictable
5398	5398	21 rate over time. The prices set by the Adjustable Block
5399	5399	22 program can be reflected as a set value or as the product
5400	5400	23 of a formula.
5401	5401	24 The Adjustable Block program shall include for each
5402	5402	25 category of eligible projects for each delivery year: a
5403	5403	26 single block of nameplate capacity, a price for renewable
5404	5404
5405	5405
5406	5406
5407	5407
5408	5408
5409	5409	HB3779 - 150 - LRB104 11172 AAS 21254 b
5410	5410
5411	5411
5412	5412	HB3779- 151 -LRB104 11172 AAS 21254 b HB3779 - 151 - LRB104 11172 AAS 21254 b
5413	5413	HB3779 - 151 - LRB104 11172 AAS 21254 b
5414	5414	1 energy credits within that block, and the terms and
5415	5415	2 conditions for securing a spot on a waitlist once the
5416	5416	3 block is fully committed or reserved. Except as outlined
5417	5417	4 below, the waitlist of projects in a given year will carry
5418	5418	5 over to apply to the subsequent year when another block is
5419	5419	6 opened. Only projects energized on or after June 1, 2017
5420	5420	7 shall be eligible for the Adjustable Block program. For
5421	5421	8 each category for each delivery year the Agency shall
5422	5422	9 determine the amount of generation capacity in each block,
5423	5423	10 and the purchase price for each block, provided that the
5424	5424	11 purchase price provided and the total amount of generation
5425	5425	12 in all blocks for all categories shall be sufficient to
5426	5426	13 meet the goals in this subsection (c). The Agency shall
5427	5427	14 strive to issue a single block sized to provide for
5428	5428	15 stability and market growth. The Agency shall establish
5429	5429	16 program eligibility requirements that ensure that projects
5430	5430	17 that enter the program are sufficiently mature to indicate
5431	5431	18 a demonstrable path to completion. The Agency may
5432	5432	19 periodically review its prior decisions establishing the
5433	5433	20 amount of generation capacity in each block, and the
5434	5434	21 purchase price for each block, and may propose, on an
5435	5435	22 expedited basis, changes to these previously set values,
5436	5436	23 including but not limited to redistributing these amounts
5437	5437	24 and the available funds as necessary and appropriate,
5438	5438	25 subject to Commission approval as part of the periodic
5439	5439	26 plan revision process described in Section 16-111.5 of the
5440	5440
5441	5441
5442	5442
5443	5443
5444	5444
5445	5445	HB3779 - 151 - LRB104 11172 AAS 21254 b
5446	5446
5447	5447
5448	5448	HB3779- 152 -LRB104 11172 AAS 21254 b HB3779 - 152 - LRB104 11172 AAS 21254 b
5449	5449	HB3779 - 152 - LRB104 11172 AAS 21254 b
5450	5450	1 Public Utilities Act. The Agency may define different
5451	5451	2 block sizes, purchase prices, or other distinct terms and
5452	5452	3 conditions for projects located in different utility
5453	5453	4 service territories if the Agency deems it necessary to
5454	5454	5 meet the goals in this subsection (c).
5455	5455	6 The Adjustable Block program shall include the
5456	5456	7 following categories in at least the following amounts:
5457	5457	8 (i) At least 20% from distributed renewable energy
5458	5458	9 generation devices with a nameplate capacity of no
5459	5459	10 more than 25 kilowatts.
5460	5460	11 (ii) At least 20% from distributed renewable
5461	5461	12 energy generation devices with a nameplate capacity of
5462	5462	13 more than 25 kilowatts and no more than 5,000
5463	5463	14 kilowatts. The Agency may create sub-categories within
5464	5464	15 this category to account for the differences between
5465	5465	16 projects for small commercial customers, large
5466	5466	17 commercial customers, and public or non-profit
5467	5467	18 customers.
5468	5468	19 (iii) At least 30% from photovoltaic community
5469	5469	20 renewable generation projects. Capacity for this
5470	5470	21 category for the first 2 delivery years after the
5471	5471	22 effective date of this amendatory Act of the 102nd
5472	5472	23 General Assembly shall be allocated to waitlist
5473	5473	24 projects as provided in paragraph (3) of item (iv) of
5474	5474	25 subparagraph (G). Starting in the third delivery year
5475	5475	26 after the effective date of this amendatory Act of the
5476	5476
5477	5477
5478	5478
5479	5479
5480	5480
5481	5481	HB3779 - 152 - LRB104 11172 AAS 21254 b
5482	5482
5483	5483
5484	5484	HB3779- 153 -LRB104 11172 AAS 21254 b HB3779 - 153 - LRB104 11172 AAS 21254 b
5485	5485	HB3779 - 153 - LRB104 11172 AAS 21254 b
5486	5486	1 102nd General Assembly or earlier if the Agency
5487	5487	2 determines there is additional capacity needed for to
5488	5488	3 meet previous delivery year requirements, the
5489	5489	4 following shall apply:
5490	5490	5 (1) the Agency shall select projects on a
5491	5491	6 first-come, first-serve basis, however the Agency
5492	5492	7 may suggest additional methods to prioritize
5493	5493	8 projects that are submitted at the same time;
5494	5494	9 (2) projects shall have subscriptions of 25 kW
5495	5495	10 or less for at least 50% of the facility's
5496	5496	11 nameplate capacity and the Agency shall price the
5497	5497	12 renewable energy credits with that as a factor;
5498	5498	13 (3) projects shall not be colocated with one
5499	5499	14 or more other community renewable generation
5500	5500	15 projects, as defined in the Agency's first revised
5501	5501	16 long-term renewable resources procurement plan
5502	5502	17 approved by the Commission on February 18, 2020,
5503	5503	18 such that the aggregate nameplate capacity exceeds
5504	5504	19 5,000 kilowatts; and
5505	5505	20 (4) projects greater than 2 MW may not apply
5506	5506	21 until after the approval of the Agency's revised
5507	5507	22 Long-Term Renewable Resources Procurement Plan
5508	5508	23 after the effective date of this amendatory Act of
5509	5509	24 the 102nd General Assembly.
5510	5510	25 (iv) At least 15% from distributed renewable
5511	5511	26 generation devices or photovoltaic community renewable
5512	5512
5513	5513
5514	5514
5515	5515
5516	5516
5517	5517	HB3779 - 153 - LRB104 11172 AAS 21254 b
5518	5518
5519	5519
5520	5520	HB3779- 154 -LRB104 11172 AAS 21254 b HB3779 - 154 - LRB104 11172 AAS 21254 b
5521	5521	HB3779 - 154 - LRB104 11172 AAS 21254 b
5522	5522	1 generation projects installed on public school land.
5523	5523	2 The Agency may create subcategories within this
5524	5524	3 category to account for the differences between
5525	5525	4 project size or location. Projects located within
5526	5526	5 environmental justice communities or within
5527	5527	6 Organizational Units that fall within Tier 1 or Tier 2
5528	5528	7 shall be given priority. Each of the Agency's periodic
5529	5529	8 updates to its long-term renewable resources
5530	5530	9 procurement plan to incorporate the procurement
5531	5531	10 described in this subparagraph (iv) shall also include
5532	5532	11 the proposed quantities or blocks, pricing, and
5533	5533	12 contract terms applicable to the procurement as
5534	5534	13 indicated herein. In each such update and procurement,
5535	5535	14 the Agency shall set the renewable energy credit price
5536	5536	15 and establish payment terms for the renewable energy
5537	5537	16 credits procured pursuant to this subparagraph (iv)
5538	5538	17 that make it feasible and affordable for public
5539	5539	18 schools to install photovoltaic distributed renewable
5540	5540	19 energy devices on their premises, including, but not
5541	5541	20 limited to, those public schools subject to the
5542	5542	21 prioritization provisions of this subparagraph. For
5543	5543	22 the purposes of this item (iv):
5544	5544	23 "Environmental Justice Community" shall have the
5545	5545	24 same meaning set forth in the Agency's long-term
5546	5546	25 renewable resources procurement plan;
5547	5547	26 "Organization Unit", "Tier 1" and "Tier 2" shall
5548	5548
5549	5549
5550	5550
5551	5551
5552	5552
5553	5553	HB3779 - 154 - LRB104 11172 AAS 21254 b
5554	5554
5555	5555
5556	5556	HB3779- 155 -LRB104 11172 AAS 21254 b HB3779 - 155 - LRB104 11172 AAS 21254 b
5557	5557	HB3779 - 155 - LRB104 11172 AAS 21254 b
5558	5558	1 have the meanings set for in Section 18-8.15 of the
5559	5559	2 School Code;
5560	5560	3 "Public schools" shall have the meaning set forth
5561	5561	4 in Section 1-3 of the School Code and includes public
5562	5562	5 institutions of higher education, as defined in the
5563	5563	6 Board of Higher Education Act.
5564	5564	7 (v) At least 5% from community-driven community
5565	5565	8 solar projects intended to provide more direct and
5566	5566	9 tangible connection and benefits to the communities
5567	5567	10 which they serve or in which they operate and,
5568	5568	11 additionally, to increase the variety of community
5569	5569	12 solar locations, models, and options in Illinois. As
5570	5570	13 part of its long-term renewable resources procurement
5571	5571	14 plan, the Agency shall develop selection criteria for
5572	5572	15 projects participating in this category. Nothing in
5573	5573	16 this Section shall preclude the Agency from creating a
5574	5574	17 selection process that maximizes community ownership
5575	5575	18 and community benefits in selecting projects to
5576	5576	19 receive renewable energy credits. Selection criteria
5577	5577	20 shall include:
5578	5578	21 (1) community ownership or community
5579	5579	22 wealth-building;
5580	5580	23 (2) additional direct and indirect community
5581	5581	24 benefit, beyond project participation as a
5582	5582	25 subscriber, including, but not limited to,
5583	5583	26 economic, environmental, social, cultural, and
5584	5584
5585	5585
5586	5586
5587	5587
5588	5588
5589	5589	HB3779 - 155 - LRB104 11172 AAS 21254 b
5590	5590
5591	5591
5592	5592	HB3779- 156 -LRB104 11172 AAS 21254 b HB3779 - 156 - LRB104 11172 AAS 21254 b
5593	5593	HB3779 - 156 - LRB104 11172 AAS 21254 b
5594	5594	1 physical benefits;
5595	5595	2 (3) meaningful involvement in project
5596	5596	3 organization and development by community members
5597	5597	4 or nonprofit organizations or public entities
5598	5598	5 located in or serving the community;
5599	5599	6 (4) engagement in project operations and
5600	5600	7 management by nonprofit organizations, public
5601	5601	8 entities, or community members; and
5602	5602	9 (5) whether a project is developed in response
5603	5603	10 to a site-specific RFP developed by community
5604	5604	11 members or a nonprofit organization or public
5605	5605	12 entity located in or serving the community.
5606	5606	13 Selection criteria may also prioritize projects
5607	5607	14 that:
5608	5608	15 (1) are developed in collaboration with or to
5609	5609	16 provide complementary opportunities for the Clean
5610	5610	17 Jobs Workforce Network Program, the Illinois
5611	5611	18 Climate Works Preapprenticeship Program, the
5612	5612	19 Returning Residents Clean Jobs Training Program,
5613	5613	20 the Clean Energy Contractor Incubator Program, or
5614	5614	21 the Clean Energy Primes Contractor Accelerator
5615	5615	22 Program;
5616	5616	23 (2) increase the diversity of locations of
5617	5617	24 community solar projects in Illinois, including by
5618	5618	25 locating in urban areas and population centers;
5619	5619	26 (3) are located in Equity Investment Eligible
5620	5620
5621	5621
5622	5622
5623	5623
5624	5624
5625	5625	HB3779 - 156 - LRB104 11172 AAS 21254 b
5626	5626
5627	5627
5628	5628	HB3779- 157 -LRB104 11172 AAS 21254 b HB3779 - 157 - LRB104 11172 AAS 21254 b
5629	5629	HB3779 - 157 - LRB104 11172 AAS 21254 b
5630	5630	1 Communities;
5631	5631	2 (4) are not greenfield projects;
5632	5632	3 (5) serve only local subscribers;
5633	5633	4 (6) have a nameplate capacity that does not
5634	5634	5 exceed 500 kW;
5635	5635	6 (7) are developed by an equity eligible
5636	5636	7 contractor; or
5637	5637	8 (8) otherwise meaningfully advance the goals
5638	5638	9 of providing more direct and tangible connection
5639	5639	10 and benefits to the communities which they serve
5640	5640	11 or in which they operate and increasing the
5641	5641	12 variety of community solar locations, models, and
5642	5642	13 options in Illinois.
5643	5643	14 For the purposes of this item (v):
5644	5644	15 "Community" means a social unit in which people
5645	5645	16 come together regularly to effect change; a social
5646	5646	17 unit in which participants are marked by a cooperative
5647	5647	18 spirit, a common purpose, or shared interests or
5648	5648	19 characteristics; or a space understood by its
5649	5649	20 residents to be delineated through geographic
5650	5650	21 boundaries or landmarks.
5651	5651	22 "Community benefit" means a range of services and
5652	5652	23 activities that provide affirmative, economic,
5653	5653	24 environmental, social, cultural, or physical value to
5654	5654	25 a community; or a mechanism that enables economic
5655	5655	26 development, high-quality employment, and education
5656	5656
5657	5657
5658	5658
5659	5659
5660	5660
5661	5661	HB3779 - 157 - LRB104 11172 AAS 21254 b
5662	5662
5663	5663
5664	5664	HB3779- 158 -LRB104 11172 AAS 21254 b HB3779 - 158 - LRB104 11172 AAS 21254 b
5665	5665	HB3779 - 158 - LRB104 11172 AAS 21254 b
5666	5666	1 opportunities for local workers and residents, or
5667	5667	2 formal monitoring and oversight structures such that
5668	5668	3 community members may ensure that those services and
5669	5669	4 activities respond to local knowledge and needs.
5670	5670	5 "Community ownership" means an arrangement in
5671	5671	6 which an electric generating facility is, or over time
5672	5672	7 will be, in significant part, owned collectively by
5673	5673	8 members of the community to which an electric
5674	5674	9 generating facility provides benefits; members of that
5675	5675	10 community participate in decisions regarding the
5676	5676	11 governance, operation, maintenance, and upgrades of
5677	5677	12 and to that facility; and members of that community
5678	5678	13 benefit from regular use of that facility.
5679	5679	14 Terms and guidance within these criteria that are
5680	5680	15 not defined in this item (v) shall be defined by the
5681	5681	16 Agency, with stakeholder input, during the development
5682	5682	17 of the Agency's long-term renewable resources
5683	5683	18 procurement plan. The Agency shall develop regular
5684	5684	19 opportunities for projects to submit applications for
5685	5685	20 projects under this category, and develop selection
5686	5686	21 criteria that gives preference to projects that better
5687	5687	22 meet individual criteria as well as projects that
5688	5688	23 address a higher number of criteria.
5689	5689	24 (vi) At least 10% from distributed renewable
5690	5690	25 energy generation devices, which includes distributed
5691	5691	26 renewable energy devices with a nameplate capacity
5692	5692
5693	5693
5694	5694
5695	5695
5696	5696
5697	5697	HB3779 - 158 - LRB104 11172 AAS 21254 b
5698	5698
5699	5699
5700	5700	HB3779- 159 -LRB104 11172 AAS 21254 b HB3779 - 159 - LRB104 11172 AAS 21254 b
5701	5701	HB3779 - 159 - LRB104 11172 AAS 21254 b
5702	5702	1 under 5,000 kilowatts or photovoltaic community
5703	5703	2 renewable generation projects, from applicants that
5704	5704	3 are equity eligible contractors. The Agency may create
5705	5705	4 subcategories within this category to account for the
5706	5706	5 differences between project size and type. The Agency
5707	5707	6 shall propose to increase the percentage in this item
5708	5708	7 (vi) over time to 40% based on factors, including, but
5709	5709	8 not limited to, the number of equity eligible
5710	5710	9 contractors and capacity used in this item (vi) in
5711	5711	10 previous delivery years.
5712	5712	11 The Agency shall propose a payment structure for
5713	5713	12 contracts executed pursuant to this paragraph under
5714	5714	13 which, upon a demonstration of qualification or need,
5715	5715	14 applicant firms are advanced capital disbursed after
5716	5716	15 contract execution but before the contracted project's
5717	5717	16 energization. The amount or percentage of capital
5718	5718	17 advanced prior to project energization shall be
5719	5719	18 sufficient to both cover any increase in development
5720	5720	19 costs resulting from prevailing wage requirements or
5721	5721	20 project-labor agreements, and designed to overcome
5722	5722	21 barriers in access to capital faced by equity eligible
5723	5723	22 contractors. The amount or percentage of advanced
5724	5724	23 capital may vary by subcategory within this category
5725	5725	24 and by an applicant's demonstration of need, with such
5726	5726	25 levels to be established through the Long-Term
5727	5727	26 Renewable Resources Procurement Plan authorized under
5728	5728
5729	5729
5730	5730
5731	5731
5732	5732
5733	5733	HB3779 - 159 - LRB104 11172 AAS 21254 b
5734	5734
5735	5735
5736	5736	HB3779- 160 -LRB104 11172 AAS 21254 b HB3779 - 160 - LRB104 11172 AAS 21254 b
5737	5737	HB3779 - 160 - LRB104 11172 AAS 21254 b
5738	5738	1 subparagraph (A) of paragraph (1) of subsection (c) of
5739	5739	2 this Section.
5740	5740	3 Contracts developed featuring capital advanced
5741	5741	4 prior to a project's energization shall feature
5742	5742	5 provisions to ensure both the successful development
5743	5743	6 of applicant projects and the delivery of the
5744	5744	7 renewable energy credits for the full term of the
5745	5745	8 contract, including ongoing collateral requirements
5746	5746	9 and other provisions deemed necessary by the Agency,
5747	5747	10 and may include energization timelines longer than for
5748	5748	11 comparable project types. The percentage or amount of
5749	5749	12 capital advanced prior to project energization shall
5750	5750	13 not operate to increase the overall contract value,
5751	5751	14 however contracts executed under this subparagraph may
5752	5752	15 feature renewable energy credit prices higher than
5753	5753	16 those offered to similar projects participating in
5754	5754	17 other categories. Capital advanced prior to
5755	5755	18 energization shall serve to reduce the ratable
5756	5756	19 payments made after energization under items (ii) and
5757	5757	20 (iii) of subparagraph (L) or payments made for each
5758	5758	21 renewable energy credit delivery under item (iv) of
5759	5759	22 subparagraph (L).
5760	5760	23 (vii) The remaining capacity shall be allocated by
5761	5761	24 the Agency in order to respond to market demand. The
5762	5762	25 Agency shall allocate any discretionary capacity prior
5763	5763	26 to the beginning of each delivery year.
5764	5764
5765	5765
5766	5766
5767	5767
5768	5768
5769	5769	HB3779 - 160 - LRB104 11172 AAS 21254 b
5770	5770
5771	5771
5772	5772	HB3779- 161 -LRB104 11172 AAS 21254 b HB3779 - 161 - LRB104 11172 AAS 21254 b
5773	5773	HB3779 - 161 - LRB104 11172 AAS 21254 b
5774	5774	1 To the extent there is uncontracted capacity from any
5775	5775	2 block in any of categories (i) through (vi) at the end of a
5776	5776	3 delivery year, the Agency shall redistribute that capacity
5777	5777	4 to one or more other categories giving priority to
5778	5778	5 categories with projects on a waitlist. The redistributed
5779	5779	6 capacity shall be added to the annual capacity in the
5780	5780	7 subsequent delivery year, and the price for renewable
5781	5781	8 energy credits shall be the price for the new delivery
5782	5782	9 year. Redistributed capacity shall not be considered
5783	5783	10 redistributed when determining whether the goals in this
5784	5784	11 subsection (K) have been met.
5785	5785	12 Notwithstanding anything to the contrary, as the
5786	5786	13 Agency increases the capacity in item (vi) to 40% over
5787	5787	14 time, the Agency may reduce the capacity of items (i)
5788	5788	15 through (v) proportionate to the capacity of the
5789	5789	16 categories of projects in item (vi), to achieve a balance
5790	5790	17 of project types.
5791	5791	18 The Adjustable Block program shall be designed to
5792	5792	19 ensure that renewable energy credits are procured from
5793	5793	20 projects in diverse locations and are not concentrated in
5794	5794	21 a few regional areas.
5795	5795	22 (L) Notwithstanding provisions for advancing capital
5796	5796	23 prior to project energization found in item (vi) of
5797	5797	24 subparagraph (K), the procurement of photovoltaic
5798	5798	25 renewable energy credits under items (i) through (vi) of
5799	5799	26 subparagraph (K) of this paragraph (1) shall otherwise be
5800	5800
5801	5801
5802	5802
5803	5803
5804	5804
5805	5805	HB3779 - 161 - LRB104 11172 AAS 21254 b
5806	5806
5807	5807
5808	5808	HB3779- 162 -LRB104 11172 AAS 21254 b HB3779 - 162 - LRB104 11172 AAS 21254 b
5809	5809	HB3779 - 162 - LRB104 11172 AAS 21254 b
5810	5810	1 subject to the following contract and payment terms:
5811	5811	2 (i) (Blank).
5812	5812	3 (ii) For those renewable energy credits that
5813	5813	4 qualify and are procured under item (i) of
5814	5814	5 subparagraph (K) of this paragraph (1), and any
5815	5815	6 similar category projects that are procured under item
5816	5816	7 (vi) of subparagraph (K) of this paragraph (1) that
5817	5817	8 qualify and are procured under item (vi), the contract
5818	5818	9 length shall be 15 years. The renewable energy credit
5819	5819	10 delivery contract value shall be paid in full, based
5820	5820	11 on the estimated generation during the first 15 years
5821	5821	12 of operation, by the contracting utilities at the time
5822	5822	13 that the facility producing the renewable energy
5823	5823	14 credits is interconnected at the distribution system
5824	5824	15 level of the utility and verified as energized and
5825	5825	16 compliant by the Program Administrator. The electric
5826	5826	17 utility shall receive and retire all renewable energy
5827	5827	18 credits generated by the project for the first 15
5828	5828	19 years of operation. Renewable energy credits generated
5829	5829	20 by the project thereafter shall not be transferred
5830	5830	21 under the renewable energy credit delivery contract
5831	5831	22 with the counterparty electric utility.
5832	5832	23 (iii) For those renewable energy credits that
5833	5833	24 qualify and are procured under item (ii) and (v) of
5834	5834	25 subparagraph (K) of this paragraph (1) and any like
5835	5835	26 projects similar category that qualify and are
5836	5836
5837	5837
5838	5838
5839	5839
5840	5840
5841	5841	HB3779 - 162 - LRB104 11172 AAS 21254 b
5842	5842
5843	5843
5844	5844	HB3779- 163 -LRB104 11172 AAS 21254 b HB3779 - 163 - LRB104 11172 AAS 21254 b
5845	5845	HB3779 - 163 - LRB104 11172 AAS 21254 b
5846	5846	1 procured under item (vi), the contract length shall be
5847	5847	2 15 years. 15% of the renewable energy credit delivery
5848	5848	3 contract value, based on the estimated generation
5849	5849	4 during the first 15 years of operation, shall be paid
5850	5850	5 by the contracting utilities at the time that the
5851	5851	6 facility producing the renewable energy credits is
5852	5852	7 interconnected at the distribution system level of the
5853	5853	8 utility and verified as energized and compliant by the
5854	5854	9 Program Administrator. The remaining portion shall be
5855	5855	10 paid ratably over the subsequent 6-year period. The
5856	5856	11 electric utility shall receive and retire all
5857	5857	12 renewable energy credits generated by the project for
5858	5858	13 the first 15 years of operation. Renewable energy
5859	5859	14 credits generated by the project thereafter shall not
5860	5860	15 be transferred under the renewable energy credit
5861	5861	16 delivery contract with the counterparty electric
5862	5862	17 utility.
5863	5863	18 (iv) For those renewable energy credits that
5864	5864	19 qualify and are procured under items (iii) and (iv) of
5865	5865	20 subparagraph (K) of this paragraph (1), and any like
5866	5866	21 projects that qualify and are procured under item
5867	5867	22 (vi), the renewable energy credit delivery contract
5868	5868	23 length shall be 20 years and shall be paid over the
5869	5869	24 delivery term, not to exceed during each delivery year
5870	5870	25 the contract price multiplied by the estimated annual
5871	5871	26 renewable energy credit generation amount. If
5872	5872
5873	5873
5874	5874
5875	5875
5876	5876
5877	5877	HB3779 - 163 - LRB104 11172 AAS 21254 b
5878	5878
5879	5879
5880	5880	HB3779- 164 -LRB104 11172 AAS 21254 b HB3779 - 164 - LRB104 11172 AAS 21254 b
5881	5881	HB3779 - 164 - LRB104 11172 AAS 21254 b
5882	5882	1 generation of renewable energy credits during a
5883	5883	2 delivery year exceeds the estimated annual generation
5884	5884	3 amount, the excess renewable energy credits shall be
5885	5885	4 carried forward to future delivery years and shall not
5886	5886	5 expire during the delivery term. If generation of
5887	5887	6 renewable energy credits during a delivery year,
5888	5888	7 including carried forward excess renewable energy
5889	5889	8 credits, if any, is less than the estimated annual
5890	5890	9 generation amount, payments during such delivery year
5891	5891	10 will not exceed the quantity generated plus the
5892	5892	11 quantity carried forward multiplied by the contract
5893	5893	12 price. The electric utility shall receive all
5894	5894	13 renewable energy credits generated by the project
5895	5895	14 during the first 20 years of operation and retire all
5896	5896	15 renewable energy credits paid for under this item (iv)
5897	5897	16 and return at the end of the delivery term all
5898	5898	17 renewable energy credits that were not paid for.
5899	5899	18 Renewable energy credits generated by the project
5900	5900	19 thereafter shall not be transferred under the
5901	5901	20 renewable energy credit delivery contract with the
5902	5902	21 counterparty electric utility. Notwithstanding the
5903	5903	22 preceding, for those projects participating under item
5904	5904	23 (iii) of subparagraph (K), the contract price for a
5905	5905	24 delivery year shall be based on subscription levels as
5906	5906	25 measured on the higher of the first business day of the
5907	5907	26 delivery year or the first business day 6 months after
5908	5908
5909	5909
5910	5910
5911	5911
5912	5912
5913	5913	HB3779 - 164 - LRB104 11172 AAS 21254 b
5914	5914
5915	5915
5916	5916	HB3779- 165 -LRB104 11172 AAS 21254 b HB3779 - 165 - LRB104 11172 AAS 21254 b
5917	5917	HB3779 - 165 - LRB104 11172 AAS 21254 b
5918	5918	1 the first business day of the delivery year.
5919	5919	2 Subscription of 90% of nameplate capacity or greater
5920	5920	3 shall be deemed to be fully subscribed for the
5921	5921	4 purposes of this item (iv). For projects receiving a
5922	5922	5 20-year delivery contract, REC prices shall be
5923	5923	6 adjusted downward for consistency with the incentive
5924	5924	7 levels previously determined to be necessary to
5925	5925	8 support projects under 15-year delivery contracts,
5926	5926	9 taking into consideration any additional new
5927	5927	10 requirements placed on the projects, including, but
5928	5928	11 not limited to, labor standards.
5929	5929	12 (v) Each contract shall include provisions to
5930	5930	13 ensure the delivery of the estimated quantity of
5931	5931	14 renewable energy credits and ongoing collateral
5932	5932	15 requirements and other provisions deemed appropriate
5933	5933	16 by the Agency.
5934	5934	17 (vi) The utility shall be the counterparty to the
5935	5935	18 contracts executed under this subparagraph (L) that
5936	5936	19 are approved by the Commission under the process
5937	5937	20 described in Section 16-111.5 of the Public Utilities
5938	5938	21 Act. No contract shall be executed for an amount that
5939	5939	22 is less than one renewable energy credit per year.
5940	5940	23 (vii) If, at any time, approved applications for
5941	5941	24 the Adjustable Block program exceed funds collected by
5942	5942	25 the electric utility or would cause the Agency to
5943	5943	26 exceed the limitation described in subparagraph (E) of
5944	5944
5945	5945
5946	5946
5947	5947
5948	5948
5949	5949	HB3779 - 165 - LRB104 11172 AAS 21254 b
5950	5950
5951	5951
5952	5952	HB3779- 166 -LRB104 11172 AAS 21254 b HB3779 - 166 - LRB104 11172 AAS 21254 b
5953	5953	HB3779 - 166 - LRB104 11172 AAS 21254 b
5954	5954	1 this paragraph (1) on the amount of renewable energy
5955	5955	2 resources that may be procured, then the Agency may
5956	5956	3 consider future uncommitted funds to be reserved for
5957	5957	4 these contracts on a first-come, first-served basis.
5958	5958	5 (viii) Nothing in this Section shall require the
5959	5959	6 utility to advance any payment or pay any amounts that
5960	5960	7 exceed the actual amount of revenues anticipated to be
5961	5961	8 collected by the utility under paragraph (6) of this
5962	5962	9 subsection (c) and subsection (k) of Section 16-108 of
5963	5963	10 the Public Utilities Act inclusive of eligible funds
5964	5964	11 collected in prior years and alternative compliance
5965	5965	12 payments for use by the utility, and contracts
5966	5966	13 executed under this Section shall expressly
5967	5967	14 incorporate this limitation.
5968	5968	15 (ix) Notwithstanding other requirements of this
5969	5969	16 subparagraph (L), no modification shall be required to
5970	5970	17 Adjustable Block program contracts if they were
5971	5971	18 already executed prior to the establishment, approval,
5972	5972	19 and implementation of new contract forms as a result
5973	5973	20 of this amendatory Act of the 102nd General Assembly.
5974	5974	21 (x) Contracts may be assignable, but only to
5975	5975	22 entities first deemed by the Agency to have met
5976	5976	23 program terms and requirements applicable to direct
5977	5977	24 program participation. In developing contracts for the
5978	5978	25 delivery of renewable energy credits, the Agency shall
5979	5979	26 be permitted to establish fees applicable to each
5980	5980
5981	5981
5982	5982
5983	5983
5984	5984
5985	5985	HB3779 - 166 - LRB104 11172 AAS 21254 b
5986	5986
5987	5987
5988	5988	HB3779- 167 -LRB104 11172 AAS 21254 b HB3779 - 167 - LRB104 11172 AAS 21254 b
5989	5989	HB3779 - 167 - LRB104 11172 AAS 21254 b
5990	5990	1 contract assignment.
5991	5991	2 (M) The Agency shall be authorized to retain one or
5992	5992	3 more experts or expert consulting firms to develop,
5993	5993	4 administer, implement, operate, and evaluate the
5994	5994	5 Adjustable Block program described in subparagraph (K) of
5995	5995	6 this paragraph (1), and the Agency shall retain the
5996	5996	7 consultant or consultants in the same manner, to the
5997	5997	8 extent practicable, as the Agency retains others to
5998	5998	9 administer provisions of this Act, including, but not
5999	5999	10 limited to, the procurement administrator. The selection
6000	6000	11 of experts and expert consulting firms and the procurement
6001	6001	12 process described in this subparagraph (M) are exempt from
6002	6002	13 the requirements of Section 20-10 of the Illinois
6003	6003	14 Procurement Code, under Section 20-10 of that Code. The
6004	6004	15 Agency shall strive to minimize administrative expenses in
6005	6005	16 the implementation of the Adjustable Block program.
6006	6006	17 The Program Administrator may charge application fees
6007	6007	18 to participating firms to cover the cost of program
6008	6008	19 administration. Any application fee amounts shall
6009	6009	20 initially be determined through the long-term renewable
6010	6010	21 resources procurement plan, and modifications to any
6011	6011	22 application fee that deviate more than 25% from the
6012	6012	23 Commission's approved value must be approved by the
6013	6013	24 Commission as a long-term plan revision under Section
6014	6014	25 16-111.5 of the Public Utilities Act. The Agency shall
6015	6015	26 consider stakeholder feedback when making adjustments to
6016	6016
6017	6017
6018	6018
6019	6019
6020	6020
6021	6021	HB3779 - 167 - LRB104 11172 AAS 21254 b
6022	6022
6023	6023
6024	6024	HB3779- 168 -LRB104 11172 AAS 21254 b HB3779 - 168 - LRB104 11172 AAS 21254 b
6025	6025	HB3779 - 168 - LRB104 11172 AAS 21254 b
6026	6026	1 application fees and shall notify stakeholders in advance
6027	6027	2 of any planned changes.
6028	6028	3 In addition to covering the costs of program
6029	6029	4 administration, the Agency, in conjunction with its
6030	6030	5 Program Administrator, may also use the proceeds of such
6031	6031	6 fees charged to participating firms to support public
6032	6032	7 education and ongoing regional and national coordination
6033	6033	8 with nonprofit organizations, public bodies, and others
6034	6034	9 engaged in the implementation of renewable energy
6035	6035	10 incentive programs or similar initiatives. This work may
6036	6036	11 include developing papers and reports, hosting regional
6037	6037	12 and national conferences, and other work deemed necessary
6038	6038	13 by the Agency to position the State of Illinois as a
6039	6039	14 national leader in renewable energy incentive program
6040	6040	15 development and administration.
6041	6041	16 The Agency and its consultant or consultants shall
6042	6042	17 monitor block activity, share program activity with
6043	6043	18 stakeholders and conduct quarterly meetings to discuss
6044	6044	19 program activity and market conditions. If necessary, the
6045	6045	20 Agency may make prospective administrative adjustments to
6046	6046	21 the Adjustable Block program design, such as making
6047	6047	22 adjustments to purchase prices as necessary to achieve the
6048	6048	23 goals of this subsection (c). Program modifications to any
6049	6049	24 block price that do not deviate from the Commission's
6050	6050	25 approved value by more than 10% shall take effect
6051	6051	26 immediately and are not subject to Commission review and
6052	6052
6053	6053
6054	6054
6055	6055
6056	6056
6057	6057	HB3779 - 168 - LRB104 11172 AAS 21254 b
6058	6058
6059	6059
6060	6060	HB3779- 169 -LRB104 11172 AAS 21254 b HB3779 - 169 - LRB104 11172 AAS 21254 b
6061	6061	HB3779 - 169 - LRB104 11172 AAS 21254 b
6062	6062	1 approval. Program modifications to any block price that
6063	6063	2 deviate more than 10% from the Commission's approved value
6064	6064	3 must be approved by the Commission as a long-term plan
6065	6065	4 amendment under Section 16-111.5 of the Public Utilities
6066	6066	5 Act. The Agency shall consider stakeholder feedback when
6067	6067	6 making adjustments to the Adjustable Block design and
6068	6068	7 shall notify stakeholders in advance of any planned
6069	6069	8 changes.
6070	6070	9 The Agency and its program administrators for both the
6071	6071	10 Adjustable Block program and the Illinois Solar for All
6072	6072	11 Program, consistent with the requirements of this
6073	6073	12 subsection (c) and subsection (b) of Section 1-56 of this
6074	6074	13 Act, shall propose the Adjustable Block program terms,
6075	6075	14 conditions, and requirements, including the prices to be
6076	6076	15 paid for renewable energy credits, where applicable, and
6077	6077	16 requirements applicable to participating entities and
6078	6078	17 project applications, through the development, review, and
6079	6079	18 approval of the Agency's long-term renewable resources
6080	6080	19 procurement plan described in this subsection (c) and
6081	6081	20 paragraph (5) of subsection (b) of Section 16-111.5 of the
6082	6082	21 Public Utilities Act. Terms, conditions, and requirements
6083	6083	22 for program participation shall include the following:
6084	6084	23 (i) The Agency shall establish a registration
6085	6085	24 process for entities seeking to qualify for
6086	6086	25 program-administered incentive funding and establish
6087	6087	26 baseline qualifications for vendor approval. The
6088	6088
6089	6089
6090	6090
6091	6091
6092	6092
6093	6093	HB3779 - 169 - LRB104 11172 AAS 21254 b
6094	6094
6095	6095
6096	6096	HB3779- 170 -LRB104 11172 AAS 21254 b HB3779 - 170 - LRB104 11172 AAS 21254 b
6097	6097	HB3779 - 170 - LRB104 11172 AAS 21254 b
6098	6098	1 Agency must maintain a list of approved entities on
6099	6099	2 each program's website, and may revoke a vendor's
6100	6100	3 ability to receive program-administered incentive
6101	6101	4 funding status upon a determination that the vendor
6102	6102	5 failed to comply with contract terms, the law, or
6103	6103	6 other program requirements.
6104	6104	7 (ii) The Agency shall establish program
6105	6105	8 requirements and minimum contract terms to ensure
6106	6106	9 projects are properly installed and produce their
6107	6107	10 expected amounts of energy. Program requirements may
6108	6108	11 include on-site inspections and photo documentation of
6109	6109	12 projects under construction. The Agency may require
6110	6110	13 repairs, alterations, or additions to remedy any
6111	6111	14 material deficiencies discovered. Vendors who have a
6112	6112	15 disproportionately high number of deficient systems
6113	6113	16 may lose their eligibility to continue to receive
6114	6114	17 State-administered incentive funding through Agency
6115	6115	18 programs and procurements.
6116	6116	19 (iii) To discourage deceptive marketing or other
6117	6117	20 bad faith business practices, the Agency may require
6118	6118	21 direct program participants, including agents
6119	6119	22 operating on their behalf, to provide standardized
6120	6120	23 disclosures to a customer prior to that customer's
6121	6121	24 execution of a contract for the development of a
6122	6122	25 distributed generation system or a subscription to a
6123	6123	26 community solar project.
6124	6124
6125	6125
6126	6126
6127	6127
6128	6128
6129	6129	HB3779 - 170 - LRB104 11172 AAS 21254 b
6130	6130
6131	6131
6132	6132	HB3779- 171 -LRB104 11172 AAS 21254 b HB3779 - 171 - LRB104 11172 AAS 21254 b
6133	6133	HB3779 - 171 - LRB104 11172 AAS 21254 b
6134	6134	1 (iv) The Agency shall establish one or multiple
6135	6135	2 Consumer Complaints Centers to accept complaints
6136	6136	3 regarding businesses that participate in, or otherwise
6137	6137	4 benefit from, State-administered incentive funding
6138	6138	5 through Agency-administered programs. The Agency shall
6139	6139	6 maintain a public database of complaints with any
6140	6140	7 confidential or particularly sensitive information
6141	6141	8 redacted from public entries.
6142	6142	9 (v) Through a filing in the proceeding for the
6143	6143	10 approval of its long-term renewable energy resources
6144	6144	11 procurement plan, the Agency shall provide an annual
6145	6145	12 written report to the Illinois Commerce Commission
6146	6146	13 documenting the frequency and nature of complaints and
6147	6147	14 any enforcement actions taken in response to those
6148	6148	15 complaints.
6149	6149	16 (vi) The Agency shall schedule regular meetings
6150	6150	17 with representatives of the Office of the Attorney
6151	6151	18 General, the Illinois Commerce Commission, consumer
6152	6152	19 protection groups, and other interested stakeholders
6153	6153	20 to share relevant information about consumer
6154	6154	21 protection, project compliance, and complaints
6155	6155	22 received.
6156	6156	23 (vii) To the extent that complaints received
6157	6157	24 implicate the jurisdiction of the Office of the
6158	6158	25 Attorney General, the Illinois Commerce Commission, or
6159	6159	26 local, State, or federal law enforcement, the Agency
6160	6160
6161	6161
6162	6162
6163	6163
6164	6164
6165	6165	HB3779 - 171 - LRB104 11172 AAS 21254 b
6166	6166
6167	6167
6168	6168	HB3779- 172 -LRB104 11172 AAS 21254 b HB3779 - 172 - LRB104 11172 AAS 21254 b
6169	6169	HB3779 - 172 - LRB104 11172 AAS 21254 b
6170	6170	1 shall also refer complaints to those entities as
6171	6171	2 appropriate.
6172	6172	3 (N) The Agency shall establish the terms, conditions,
6173	6173	4 and program requirements for photovoltaic community
6174	6174	5 renewable generation projects with a goal to expand access
6175	6175	6 to a broader group of energy consumers, to ensure robust
6176	6176	7 participation opportunities for residential and small
6177	6177	8 commercial customers and those who cannot install
6178	6178	9 renewable energy on their own properties. Subject to
6179	6179	10 reasonable limitations, any plan approved by the
6180	6180	11 Commission shall allow subscriptions to community
6181	6181	12 renewable generation projects to be portable and
6182	6182	13 transferable. For purposes of this subparagraph (N),
6183	6183	14 "portable" means that subscriptions may be retained by the
6184	6184	15 subscriber even if the subscriber relocates or changes its
6185	6185	16 address within the same utility service territory; and
6186	6186	17 "transferable" means that a subscriber may assign or sell
6187	6187	18 subscriptions to another person within the same utility
6188	6188	19 service territory.
6189	6189	20 Through the development of its long-term renewable
6190	6190	21 resources procurement plan, the Agency may consider
6191	6191	22 whether community renewable generation projects utilizing
6192	6192	23 technologies other than photovoltaics should be supported
6193	6193	24 through State-administered incentive funding, and may
6194	6194	25 issue requests for information to gauge market demand.
6195	6195	26 Electric utilities shall provide a monetary credit to
6196	6196
6197	6197
6198	6198
6199	6199
6200	6200
6201	6201	HB3779 - 172 - LRB104 11172 AAS 21254 b
6202	6202
6203	6203
6204	6204	HB3779- 173 -LRB104 11172 AAS 21254 b HB3779 - 173 - LRB104 11172 AAS 21254 b
6205	6205	HB3779 - 173 - LRB104 11172 AAS 21254 b
6206	6206	1 a subscriber's subsequent bill for service for the
6207	6207	2 proportional output of a community renewable generation
6208	6208	3 project attributable to that subscriber as specified in
6209	6209	4 Section 16-107.5 of the Public Utilities Act.
6210	6210	5 The Agency shall purchase renewable energy credits
6211	6211	6 from subscribed shares of photovoltaic community renewable
6212	6212	7 generation projects through the Adjustable Block program
6213	6213	8 described in subparagraph (K) of this paragraph (1) or
6214	6214	9 through the Illinois Solar for All Program described in
6215	6215	10 Section 1-56 of this Act. The electric utility shall
6216	6216	11 purchase any unsubscribed energy from community renewable
6217	6217	12 generation projects that are Qualifying Facilities ("QF")
6218	6218	13 under the electric utility's tariff for purchasing the
6219	6219	14 output from QFs under Public Utilities Regulatory Policies
6220	6220	15 Act of 1978.
6221	6221	16 The owners of and any subscribers to a community
6222	6222	17 renewable generation project shall not be considered
6223	6223	18 public utilities or alternative retail electricity
6224	6224	19 suppliers under the Public Utilities Act solely as a
6225	6225	20 result of their interest in or subscription to a community
6226	6226	21 renewable generation project and shall not be required to
6227	6227	22 become an alternative retail electric supplier by
6228	6228	23 participating in a community renewable generation project
6229	6229	24 with a public utility.
6230	6230	25 (O) For the delivery year beginning June 1, 2018, the
6231	6231	26 long-term renewable resources procurement plan required by
6232	6232
6233	6233
6234	6234
6235	6235
6236	6236
6237	6237	HB3779 - 173 - LRB104 11172 AAS 21254 b
6238	6238
6239	6239
6240	6240	HB3779- 174 -LRB104 11172 AAS 21254 b HB3779 - 174 - LRB104 11172 AAS 21254 b
6241	6241	HB3779 - 174 - LRB104 11172 AAS 21254 b
6242	6242	1 this subsection (c) shall provide for the Agency to
6243	6243	2 procure contracts to continue offering the Illinois Solar
6244	6244	3 for All Program described in subsection (b) of Section
6245	6245	4 1-56 of this Act, and the contracts approved by the
6246	6246	5 Commission shall be executed by the utilities that are
6247	6247	6 subject to this subsection (c). The long-term renewable
6248	6248	7 resources procurement plan shall allocate up to
6249	6249	8 $50,000,000 per delivery year to fund the programs, and
6250	6250	9 the plan shall determine the amount of funding to be
6251	6251	10 apportioned to the programs identified in subsection (b)
6252	6252	11 of Section 1-56 of this Act; provided that for the
6253	6253	12 delivery years beginning June 1, 2021, June 1, 2022, and
6254	6254	13 June 1, 2023, the long-term renewable resources
6255	6255	14 procurement plan may average the annual budgets over a
6256	6256	15 3-year period to account for program ramp-up. For the
6257	6257	16 delivery years beginning June 1, 2021, June 1, 2024, June
6258	6258	17 1, 2027, and June 1, 2030 and additional $10,000,000 shall
6259	6259	18 be provided to the Department of Commerce and Economic
6260	6260	19 Opportunity to implement the workforce development
6261	6261	20 programs and reporting as outlined in Section 16-108.12 of
6262	6262	21 the Public Utilities Act. In making the determinations
6263	6263	22 required under this subparagraph (O), the Commission shall
6264	6264	23 consider the experience and performance under the programs
6265	6265	24 and any evaluation reports. The Commission shall also
6266	6266	25 provide for an independent evaluation of those programs on
6267	6267	26 a periodic basis that are funded under this subparagraph
6268	6268
6269	6269
6270	6270
6271	6271
6272	6272
6273	6273	HB3779 - 174 - LRB104 11172 AAS 21254 b
6274	6274
6275	6275
6276	6276	HB3779- 175 -LRB104 11172 AAS 21254 b HB3779 - 175 - LRB104 11172 AAS 21254 b
6277	6277	HB3779 - 175 - LRB104 11172 AAS 21254 b
6278	6278	1 (O).
6279	6279	2 (P) All programs and procurements under this
6280	6280	3 subsection (c) shall be designed to encourage
6281	6281	4 participating projects to use a diverse and equitable
6282	6282	5 workforce and a diverse set of contractors, including
6283	6283	6 minority-owned businesses, disadvantaged businesses,
6284	6284	7 trade unions, graduates of any workforce training programs
6285	6285	8 administered under this Act, and small businesses.
6286	6286	9 The Agency shall develop a method to optimize
6287	6287	10 procurement of renewable energy credits from proposed
6288	6288	11 utility-scale projects that are located in communities
6289	6289	12 eligible to receive Energy Transition Community Grants
6290	6290	13 pursuant to Section 10-20 of the Energy Community
6291	6291	14 Reinvestment Act. If this requirement conflicts with other
6292	6292	15 provisions of law or the Agency determines that full
6293	6293	16 compliance with the requirements of this subparagraph (P)
6294	6294	17 would be unreasonably costly or administratively
6295	6295	18 impractical, the Agency is to propose alternative
6296	6296	19 approaches to achieve development of renewable energy
6297	6297	20 resources in communities eligible to receive Energy
6298	6298	21 Transition Community Grants pursuant to Section 10-20 of
6299	6299	22 the Energy Community Reinvestment Act or seek an exemption
6300	6300	23 from this requirement from the Commission.
6301	6301	24 (Q) Each facility listed in subitems (i) through (ix)
6302	6302	25 of item (1) of this subparagraph (Q) for which a renewable
6303	6303	26 energy credit delivery contract is signed after the
6304	6304
6305	6305
6306	6306
6307	6307
6308	6308
6309	6309	HB3779 - 175 - LRB104 11172 AAS 21254 b
6310	6310
6311	6311
6312	6312	HB3779- 176 -LRB104 11172 AAS 21254 b HB3779 - 176 - LRB104 11172 AAS 21254 b
6313	6313	HB3779 - 176 - LRB104 11172 AAS 21254 b
6314	6314	1 effective date of this amendatory Act of the 102nd General
6315	6315	2 Assembly is subject to the following requirements through
6316	6316	3 the Agency's long-term renewable resources procurement
6317	6317	4 plan:
6318	6318	5 (1) Each facility shall be subject to the
6319	6319	6 prevailing wage requirements included in the
6320	6320	7 Prevailing Wage Act. The Agency shall require
6321	6321	8 verification that all construction performed on the
6322	6322	9 facility by the renewable energy credit delivery
6323	6323	10 contract holder, its contractors, or its
6324	6324	11 subcontractors relating to construction of the
6325	6325	12 facility is performed by construction employees
6326	6326	13 receiving an amount for that work equal to or greater
6327	6327	14 than the general prevailing rate, as that term is
6328	6328	15 defined in Section 3 of the Prevailing Wage Act. For
6329	6329	16 purposes of this item (1), "house of worship" means
6330	6330	17 property that is both (1) used exclusively by a
6331	6331	18 religious society or body of persons as a place for
6332	6332	19 religious exercise or religious worship and (2)
6333	6333	20 recognized as exempt from taxation pursuant to Section
6334	6334	21 15-40 of the Property Tax Code. This item (1) shall
6335	6335	22 apply to any the following:
6336	6336	23 (i) all new utility-scale wind projects;
6337	6337	24 (ii) all new utility-scale photovoltaic
6338	6338	25 projects;
6339	6339	26 (iii) all new brownfield photovoltaic
6340	6340
6341	6341
6342	6342
6343	6343
6344	6344
6345	6345	HB3779 - 176 - LRB104 11172 AAS 21254 b
6346	6346
6347	6347
6348	6348	HB3779- 177 -LRB104 11172 AAS 21254 b HB3779 - 177 - LRB104 11172 AAS 21254 b
6349	6349	HB3779 - 177 - LRB104 11172 AAS 21254 b
6350	6350	1 projects;
6351	6351	2 (iv) all new photovoltaic community renewable
6352	6352	3 energy facilities that qualify for item (iii) of
6353	6353	4 subparagraph (K) of this paragraph (1);
6354	6354	5 (v) all new community driven community
6355	6355	6 photovoltaic projects that qualify for item (v) of
6356	6356	7 subparagraph (K) of this paragraph (1);
6357	6357	8 (vi) all new photovoltaic projects on public
6358	6358	9 school land that qualify for item (iv) of
6359	6359	10 subparagraph (K) of this paragraph (1);
6360	6360	11 (vii) all new photovoltaic distributed
6361	6361	12 renewable energy generation devices that (1)
6362	6362	13 qualify for item (i) of subparagraph (K) of this
6363	6363	14 paragraph (1); (2) are not projects that serve
6364	6364	15 single-family or multi-family residential
6365	6365	16 buildings; and (3) are not houses of worship where
6366	6366	17 the aggregate capacity including collocated
6367	6367	18 projects would not exceed 100 kilowatts;
6368	6368	19 (viii) all new photovoltaic distributed
6369	6369	20 renewable energy generation devices that (1)
6370	6370	21 qualify for item (ii) of subparagraph (K) of this
6371	6371	22 paragraph (1); (2) are not projects that serve
6372	6372	23 single-family or multi-family residential
6373	6373	24 buildings; and (3) are not houses of worship where
6374	6374	25 the aggregate capacity including collocated
6375	6375	26 projects would not exceed 100 kilowatts;
6376	6376
6377	6377
6378	6378
6379	6379
6380	6380
6381	6381	HB3779 - 177 - LRB104 11172 AAS 21254 b
6382	6382
6383	6383
6384	6384	HB3779- 178 -LRB104 11172 AAS 21254 b HB3779 - 178 - LRB104 11172 AAS 21254 b
6385	6385	HB3779 - 178 - LRB104 11172 AAS 21254 b
6386	6386	1 (ix) all new, modernized, or retooled
6387	6387	2 hydropower facilities.
6388	6388	3 (2) Renewable energy credits procured from new
6389	6389	4 utility-scale wind projects, new utility-scale solar
6390	6390	5 projects, and new brownfield solar projects pursuant
6391	6391	6 to Agency procurement events occurring after the
6392	6392	7 effective date of this amendatory Act of the 102nd
6393	6393	8 General Assembly must be from facilities built by
6394	6394	9 general contractors that must enter into a project
6395	6395	10 labor agreement, as defined by this Act, prior to
6396	6396	11 construction. The project labor agreement shall be
6397	6397	12 filed with the Director in accordance with procedures
6398	6398	13 established by the Agency through its long-term
6399	6399	14 renewable resources procurement plan. Any information
6400	6400	15 submitted to the Agency in this item (2) shall be
6401	6401	16 considered commercially sensitive information. At a
6402	6402	17 minimum, the project labor agreement must provide the
6403	6403	18 names, addresses, and occupations of the owner of the
6404	6404	19 plant and the individuals representing the labor
6405	6405	20 organization employees participating in the project
6406	6406	21 labor agreement consistent with the Project Labor
6407	6407	22 Agreements Act. The agreement must also specify the
6408	6408	23 terms and conditions as defined by this Act.
6409	6409	24 (3) It is the intent of this Section to ensure that
6410	6410	25 economic development occurs across Illinois
6411	6411	26 communities, that emerging businesses may grow, and
6412	6412
6413	6413
6414	6414
6415	6415
6416	6416
6417	6417	HB3779 - 178 - LRB104 11172 AAS 21254 b
6418	6418
6419	6419
6420	6420	HB3779- 179 -LRB104 11172 AAS 21254 b HB3779 - 179 - LRB104 11172 AAS 21254 b
6421	6421	HB3779 - 179 - LRB104 11172 AAS 21254 b
6422	6422	1 that there is improved access to the clean energy
6423	6423	2 economy by persons who have greater economic burdens
6424	6424	3 to success. The Agency shall take into consideration
6425	6425	4 the unique cost of compliance of this subparagraph (Q)
6426	6426	5 that might be borne by equity eligible contractors,
6427	6427	6 shall include such costs when determining the price of
6428	6428	7 renewable energy credits in the Adjustable Block
6429	6429	8 program, and shall take such costs into consideration
6430	6430	9 in a nondiscriminatory manner when comparing bids for
6431	6431	10 competitive procurements. The Agency shall consider
6432	6432	11 costs associated with compliance whether in the
6433	6433	12 development, financing, or construction of projects.
6434	6434	13 The Agency shall periodically review the assumptions
6435	6435	14 in these costs and may adjust prices, in compliance
6436	6436	15 with subparagraph (M) of this paragraph (1).
6437	6437	16 (R) In its long-term renewable resources procurement
6438	6438	17 plan, the Agency shall establish a self-direct renewable
6439	6439	18 portfolio standard compliance program for eligible
6440	6440	19 self-direct customers that purchase renewable energy
6441	6441	20 credits from utility-scale wind and solar projects through
6442	6442	21 long-term agreements for purchase of renewable energy
6443	6443	22 credits as described in this Section. Such long-term
6444	6444	23 agreements may include the purchase of energy or other
6445	6445	24 products on a physical or financial basis and may involve
6446	6446	25 an alternative retail electric supplier as defined in
6447	6447	26 Section 16-102 of the Public Utilities Act. This program
6448	6448
6449	6449
6450	6450
6451	6451
6452	6452
6453	6453	HB3779 - 179 - LRB104 11172 AAS 21254 b
6454	6454
6455	6455
6456	6456	HB3779- 180 -LRB104 11172 AAS 21254 b HB3779 - 180 - LRB104 11172 AAS 21254 b
6457	6457	HB3779 - 180 - LRB104 11172 AAS 21254 b
6458	6458	1 shall take effect in the delivery year commencing June 1,
6459	6459	2 2023.
6460	6460	3 (1) For the purposes of this subparagraph:
6461	6461	4 "Eligible self-direct customer" means any retail
6462	6462	5 customers of an electric utility that serves 3,000,000
6463	6463	6 or more retail customers in the State and whose total
6464	6464	7 highest 30-minute demand was more than 10,000
6465	6465	8 kilowatts, or any retail customers of an electric
6466	6466	9 utility that serves less than 3,000,000 retail
6467	6467	10 customers but more than 500,000 retail customers in
6468	6468	11 the State and whose total highest 15-minute demand was
6469	6469	12 more than 10,000 kilowatts.
6470	6470	13 "Retail customer" has the meaning set forth in
6471	6471	14 Section 16-102 of the Public Utilities Act and
6472	6472	15 multiple retail customer accounts under the same
6473	6473	16 corporate parent may aggregate their account demands
6474	6474	17 to meet the 10,000 kilowatt threshold. The criteria
6475	6475	18 for determining whether this subparagraph is
6476	6476	19 applicable to a retail customer shall be based on the
6477	6477	20 12 consecutive billing periods prior to the start of
6478	6478	21 the year in which the application is filed.
6479	6479	22 (2) For renewable energy credits to count toward
6480	6480	23 the self-direct renewable portfolio standard
6481	6481	24 compliance program, they must:
6482	6482	25 (i) qualify as renewable energy credits as
6483	6483	26 defined in Section 1-10 of this Act;
6484	6484
6485	6485
6486	6486
6487	6487
6488	6488
6489	6489	HB3779 - 180 - LRB104 11172 AAS 21254 b
6490	6490
6491	6491
6492	6492	HB3779- 181 -LRB104 11172 AAS 21254 b HB3779 - 181 - LRB104 11172 AAS 21254 b
6493	6493	HB3779 - 181 - LRB104 11172 AAS 21254 b
6494	6494	1 (ii) be sourced from one or more renewable
6495	6495	2 energy generating facilities that comply with the
6496	6496	3 geographic requirements as set forth in
6497	6497	4 subparagraph (I) of paragraph (1) of subsection
6498	6498	5 (c) as interpreted through the Agency's long-term
6499	6499	6 renewable resources procurement plan, or, where
6500	6500	7 applicable, the geographic requirements that
6501	6501	8 governed utility-scale renewable energy credits at
6502	6502	9 the time the eligible self-direct customer entered
6503	6503	10 into the applicable renewable energy credit
6504	6504	11 purchase agreement;
6505	6505	12 (iii) be procured through long-term contracts
6506	6506	13 with term lengths of at least 10 years either
6507	6507	14 directly with the renewable energy generating
6508	6508	15 facility or through a bundled power purchase
6509	6509	16 agreement, a virtual power purchase agreement, an
6510	6510	17 agreement between the renewable generating
6511	6511	18 facility, an alternative retail electric supplier,
6512	6512	19 and the customer, or such other structure as is
6513	6513	20 permissible under this subparagraph (R);
6514	6514	21 (iv) be equivalent in volume to at least 40%
6515	6515	22 of the eligible self-direct customer's usage,
6516	6516	23 determined annually by the eligible self-direct
6517	6517	24 customer's usage during the previous delivery
6518	6518	25 year, measured to the nearest megawatt-hour;
6519	6519	26 (v) be retired by or on behalf of the large
6520	6520
6521	6521
6522	6522
6523	6523
6524	6524
6525	6525	HB3779 - 181 - LRB104 11172 AAS 21254 b
6526	6526
6527	6527
6528	6528	HB3779- 182 -LRB104 11172 AAS 21254 b HB3779 - 182 - LRB104 11172 AAS 21254 b
6529	6529	HB3779 - 182 - LRB104 11172 AAS 21254 b
6530	6530	1 energy customer;
6531	6531	2 (vi) be sourced from new utility-scale wind
6532	6532	3 projects or new utility-scale solar projects; and
6533	6533	4 (vii) if the contracts for renewable energy
6534	6534	5 credits are entered into after the effective date
6535	6535	6 of this amendatory Act of the 102nd General
6536	6536	7 Assembly, the new utility-scale wind projects or
6537	6537	8 new utility-scale solar projects must comply with
6538	6538	9 the requirements established in subparagraphs (P)
6539	6539	10 and (Q) of paragraph (1) of this subsection (c)
6540	6540	11 and subsection (c-10).
6541	6541	12 (3) The self-direct renewable portfolio standard
6542	6542	13 compliance program shall be designed to allow eligible
6543	6543	14 self-direct customers to procure new renewable energy
6544	6544	15 credits from new utility-scale wind projects or new
6545	6545	16 utility-scale photovoltaic projects. The Agency shall
6546	6546	17 annually determine the amount of utility-scale
6547	6547	18 renewable energy credits it will include each year
6548	6548	19 from the self-direct renewable portfolio standard
6549	6549	20 compliance program, subject to receiving qualifying
6550	6550	21 applications. In making this determination, the Agency
6551	6551	22 shall evaluate publicly available analyses and studies
6552	6552	23 of the potential market size for utility-scale
6553	6553	24 renewable energy long-term purchase agreements by
6554	6554	25 commercial and industrial energy customers and make
6555	6555	26 that report publicly available. If demand for
6556	6556
6557	6557
6558	6558
6559	6559
6560	6560
6561	6561	HB3779 - 182 - LRB104 11172 AAS 21254 b
6562	6562
6563	6563
6564	6564	HB3779- 183 -LRB104 11172 AAS 21254 b HB3779 - 183 - LRB104 11172 AAS 21254 b
6565	6565	HB3779 - 183 - LRB104 11172 AAS 21254 b
6566	6566	1 participation in the self-direct renewable portfolio
6567	6567	2 standard compliance program exceeds availability, the
6568	6568	3 Agency shall ensure participation is evenly split
6569	6569	4 between commercial and industrial users to the extent
6570	6570	5 there is sufficient demand from both customer classes.
6571	6571	6 Each renewable energy credit procured pursuant to this
6572	6572	7 subparagraph (R) by a self-direct customer shall
6573	6573	8 reduce the total volume of renewable energy credits
6574	6574	9 the Agency is otherwise required to procure from new
6575	6575	10 utility-scale projects pursuant to subparagraph (C) of
6576	6576	11 paragraph (1) of this subsection (c) on behalf of
6577	6577	12 contracting utilities where the eligible self-direct
6578	6578	13 customer is located. The self-direct customer shall
6579	6579	14 file an annual compliance report with the Agency
6580	6580	15 pursuant to terms established by the Agency through
6581	6581	16 its long-term renewable resources procurement plan to
6582	6582	17 be eligible for participation in this program.
6583	6583	18 Customers must provide the Agency with their most
6584	6584	19 recent electricity billing statements or other
6585	6585	20 information deemed necessary by the Agency to
6586	6586	21 demonstrate they are an eligible self-direct customer.
6587	6587	22 (4) The Commission shall approve a reduction in
6588	6588	23 the volumetric charges collected pursuant to Section
6589	6589	24 16-108 of the Public Utilities Act for approved
6590	6590	25 eligible self-direct customers equivalent to the
6591	6591	26 anticipated cost of renewable energy credit deliveries
6592	6592
6593	6593
6594	6594
6595	6595
6596	6596
6597	6597	HB3779 - 183 - LRB104 11172 AAS 21254 b
6598	6598
6599	6599
6600	6600	HB3779- 184 -LRB104 11172 AAS 21254 b HB3779 - 184 - LRB104 11172 AAS 21254 b
6601	6601	HB3779 - 184 - LRB104 11172 AAS 21254 b
6602	6602	1 under contracts for new utility-scale wind and new
6603	6603	2 utility-scale solar entered for each delivery year
6604	6604	3 after the large energy customer begins retiring
6605	6605	4 eligible new utility scale renewable energy credits
6606	6606	5 for self-compliance. The self-direct credit amount
6607	6607	6 shall be determined annually and is equal to the
6608	6608	7 estimated portion of the cost authorized by
6609	6609	8 subparagraph (E) of paragraph (1) of this subsection
6610	6610	9 (c) that supported the annual procurement of
6611	6611	10 utility-scale renewable energy credits in the prior
6612	6612	11 delivery year using a methodology described in the
6613	6613	12 long-term renewable resources procurement plan,
6614	6614	13 expressed on a per kilowatthour basis, and does not
6615	6615	14 include (i) costs associated with any contracts
6616	6616	15 entered into before the delivery year in which the
6617	6617	16 customer files the initial compliance report to be
6618	6618	17 eligible for participation in the self-direct program,
6619	6619	18 and (ii) costs associated with procuring renewable
6620	6620	19 energy credits through existing and future contracts
6621	6621	20 through the Adjustable Block Program, subsection (c-5)
6622	6622	21 of this Section 1-75, and the Solar for All Program.
6623	6623	22 The Agency shall assist the Commission in determining
6624	6624	23 the current and future costs. The Agency must
6625	6625	24 determine the self-direct credit amount for new and
6626	6626	25 existing eligible self-direct customers and submit
6627	6627	26 this to the Commission in an annual compliance filing.
6628	6628
6629	6629
6630	6630
6631	6631
6632	6632
6633	6633	HB3779 - 184 - LRB104 11172 AAS 21254 b
6634	6634
6635	6635
6636	6636	HB3779- 185 -LRB104 11172 AAS 21254 b HB3779 - 185 - LRB104 11172 AAS 21254 b
6637	6637	HB3779 - 185 - LRB104 11172 AAS 21254 b
6638	6638	1 The Commission must approve the self-direct credit
6639	6639	2 amount by June 1, 2023 and June 1 of each delivery year
6640	6640	3 thereafter.
6641	6641	4 (5) Customers described in this subparagraph (R)
6642	6642	5 shall apply, on a form developed by the Agency, to the
6643	6643	6 Agency to be designated as a self-direct eligible
6644	6644	7 customer. Once the Agency determines that a
6645	6645	8 self-direct customer is eligible for participation in
6646	6646	9 the program, the self-direct customer will remain
6647	6647	10 eligible until the end of the term of the contract.
6648	6648	11 Thereafter, application may be made not less than 12
6649	6649	12 months before the filing date of the long-term
6650	6650	13 renewable resources procurement plan described in this
6651	6651	14 Act. At a minimum, such application shall contain the
6652	6652	15 following:
6653	6653	16 (i) the customer's certification that, at the
6654	6654	17 time of the customer's application, the customer
6655	6655	18 qualifies to be a self-direct eligible customer,
6656	6656	19 including documents demonstrating that
6657	6657	20 qualification;
6658	6658	21 (ii) the customer's certification that the
6659	6659	22 customer has entered into or will enter into by
6660	6660	23 the beginning of the applicable procurement year,
6661	6661	24 one or more bilateral contracts for new wind
6662	6662	25 projects or new photovoltaic projects, including
6663	6663	26 supporting documentation;
6664	6664
6665	6665
6666	6666
6667	6667
6668	6668
6669	6669	HB3779 - 185 - LRB104 11172 AAS 21254 b
6670	6670
6671	6671
6672	6672	HB3779- 186 -LRB104 11172 AAS 21254 b HB3779 - 186 - LRB104 11172 AAS 21254 b
6673	6673	HB3779 - 186 - LRB104 11172 AAS 21254 b
6674	6674	1 (iii) certification that the contract or
6675	6675	2 contracts for new renewable energy resources are
6676	6676	3 long-term contracts with term lengths of at least
6677	6677	4 10 years, including supporting documentation;
6678	6678	5 (iv) certification of the quantities of
6679	6679	6 renewable energy credits that the customer will
6680	6680	7 purchase each year under such contract or
6681	6681	8 contracts, including supporting documentation;
6682	6682	9 (v) proof that the contract is sufficient to
6683	6683	10 produce renewable energy credits to be equivalent
6684	6684	11 in volume to at least 40% of the large energy
6685	6685	12 customer's usage from the previous delivery year,
6686	6686	13 measured to the nearest megawatt-hour; and
6687	6687	14 (vi) certification that the customer intends
6688	6688	15 to maintain the contract for the duration of the
6689	6689	16 length of the contract.
6690	6690	17 (6) If a customer receives the self-direct credit
6691	6691	18 but fails to properly procure and retire renewable
6692	6692	19 energy credits as required under this subparagraph
6693	6693	20 (R), the Commission, on petition from the Agency and
6694	6694	21 after notice and hearing, may direct such customer's
6695	6695	22 utility to recover the cost of the wrongfully received
6696	6696	23 self-direct credits plus interest through an adder to
6697	6697	24 charges assessed pursuant to Section 16-108 of the
6698	6698	25 Public Utilities Act. Self-direct customers who
6699	6699	26 knowingly fail to properly procure and retire
6700	6700
6701	6701
6702	6702
6703	6703
6704	6704
6705	6705	HB3779 - 186 - LRB104 11172 AAS 21254 b
6706	6706
6707	6707
6708	6708	HB3779- 187 -LRB104 11172 AAS 21254 b HB3779 - 187 - LRB104 11172 AAS 21254 b
6709	6709	HB3779 - 187 - LRB104 11172 AAS 21254 b
6710	6710	1 renewable energy credits and do not notify the Agency
6711	6711	2 are ineligible for continued participation in the
6712	6712	3 self-direct renewable portfolio standard compliance
6713	6713	4 program.
6714	6714	5 (2) (Blank).
6715	6715	6 (3) (Blank).
6716	6716	7 (4) The electric utility shall retire all renewable
6717	6717	8 energy credits used to comply with the standard.
6718	6718	9 (5) Beginning with the 2010 delivery year and ending
6719	6719	10 June 1, 2017, an electric utility subject to this
6720	6720	11 subsection (c) shall apply the lesser of the maximum
6721	6721	12 alternative compliance payment rate or the most recent
6722	6722	13 estimated alternative compliance payment rate for its
6723	6723	14 service territory for the corresponding compliance period,
6724	6724	15 established pursuant to subsection (d) of Section 16-115D
6725	6725	16 of the Public Utilities Act to its retail customers that
6726	6726	17 take service pursuant to the electric utility's hourly
6727	6727	18 pricing tariff or tariffs. The electric utility shall
6728	6728	19 retain all amounts collected as a result of the
6729	6729	20 application of the alternative compliance payment rate or
6730	6730	21 rates to such customers, and, beginning in 2011, the
6731	6731	22 utility shall include in the information provided under
6732	6732	23 item (1) of subsection (d) of Section 16-111.5 of the
6733	6733	24 Public Utilities Act the amounts collected under the
6734	6734	25 alternative compliance payment rate or rates for the prior
6735	6735	26 year ending May 31. Notwithstanding any limitation on the
6736	6736
6737	6737
6738	6738
6739	6739
6740	6740
6741	6741	HB3779 - 187 - LRB104 11172 AAS 21254 b
6742	6742
6743	6743
6744	6744	HB3779- 188 -LRB104 11172 AAS 21254 b HB3779 - 188 - LRB104 11172 AAS 21254 b
6745	6745	HB3779 - 188 - LRB104 11172 AAS 21254 b
6746	6746	1 procurement of renewable energy resources imposed by item
6747	6747	2 (2) of this subsection (c), the Agency shall increase its
6748	6748	3 spending on the purchase of renewable energy resources to
6749	6749	4 be procured by the electric utility for the next plan year
6750	6750	5 by an amount equal to the amounts collected by the utility
6751	6751	6 under the alternative compliance payment rate or rates in
6752	6752	7 the prior year ending May 31.
6753	6753	8 (6) The electric utility shall be entitled to recover
6754	6754	9 all of its costs associated with the procurement of
6755	6755	10 renewable energy credits under plans approved under this
6756	6756	11 Section and Section 16-111.5 of the Public Utilities Act.
6757	6757	12 These costs shall include associated reasonable expenses
6758	6758	13 for implementing the procurement programs, including, but
6759	6759	14 not limited to, the costs of administering and evaluating
6760	6760	15 the Adjustable Block program, through an automatic
6761	6761	16 adjustment clause tariff in accordance with subsection (k)
6762	6762	17 of Section 16-108 of the Public Utilities Act.
6763	6763	18 (7) Renewable energy credits procured from new
6764	6764	19 photovoltaic projects or new distributed renewable energy
6765	6765	20 generation devices under this Section after June 1, 2017
6766	6766	21 (the effective date of Public Act 99-906) must be procured
6767	6767	22 from devices installed by a qualified person in compliance
6768	6768	23 with the requirements of Section 16-128A of the Public
6769	6769	24 Utilities Act and any rules or regulations adopted
6770	6770	25 thereunder.
6771	6771	26 In meeting the renewable energy requirements of this
6772	6772
6773	6773
6774	6774
6775	6775
6776	6776
6777	6777	HB3779 - 188 - LRB104 11172 AAS 21254 b
6778	6778
6779	6779
6780	6780	HB3779- 189 -LRB104 11172 AAS 21254 b HB3779 - 189 - LRB104 11172 AAS 21254 b
6781	6781	HB3779 - 189 - LRB104 11172 AAS 21254 b
6782	6782	1 subsection (c), to the extent feasible and consistent with
6783	6783	2 State and federal law, the renewable energy credit
6784	6784	3 procurements, Adjustable Block solar program, and
6785	6785	4 community renewable generation program shall provide
6786	6786	5 employment opportunities for all segments of the
6787	6787	6 population and workforce, including minority-owned and
6788	6788	7 female-owned business enterprises, and shall not,
6789	6789	8 consistent with State and federal law, discriminate based
6790	6790	9 on race or socioeconomic status.
6791	6791	10 (c-5) Procurement of renewable energy credits from new
6792	6792	11 renewable energy facilities installed at or adjacent to the
6793	6793	12 sites of electric generating facilities that burn or burned
6794	6794	13 coal as their primary fuel source.
6795	6795	14 (1) In addition to the procurement of renewable energy
6796	6796	15 credits pursuant to long-term renewable resources
6797	6797	16 procurement plans in accordance with subsection (c) of
6798	6798	17 this Section and Section 16-111.5 of the Public Utilities
6799	6799	18 Act, the Agency shall conduct procurement events in
6800	6800	19 accordance with this subsection (c-5) for the procurement
6801	6801	20 by electric utilities that served more than 300,000 retail
6802	6802	21 customers in this State as of January 1, 2019 of renewable
6803	6803	22 energy credits from new renewable energy facilities to be
6804	6804	23 installed at or adjacent to the sites of electric
6805	6805	24 generating facilities that, as of January 1, 2016, burned
6806	6806	25 coal as their primary fuel source and meet the other
6807	6807	26 criteria specified in this subsection (c-5). For purposes
6808	6808
6809	6809
6810	6810
6811	6811
6812	6812
6813	6813	HB3779 - 189 - LRB104 11172 AAS 21254 b
6814	6814
6815	6815
6816	6816	HB3779- 190 -LRB104 11172 AAS 21254 b HB3779 - 190 - LRB104 11172 AAS 21254 b
6817	6817	HB3779 - 190 - LRB104 11172 AAS 21254 b
6818	6818	1 of this subsection (c-5), "new renewable energy facility"
6819	6819	2 means a new utility-scale solar project as defined in this
6820	6820	3 Section 1-75. The renewable energy credits procured
6821	6821	4 pursuant to this subsection (c-5) may be included or
6822	6822	5 counted for purposes of compliance with the amounts of
6823	6823	6 renewable energy credits required to be procured pursuant
6824	6824	7 to subsection (c) of this Section to the extent that there
6825	6825	8 are otherwise shortfalls in compliance with such
6826	6826	9 requirements. The procurement of renewable energy credits
6827	6827	10 by electric utilities pursuant to this subsection (c-5)
6828	6828	11 shall be funded solely by revenues collected from the Coal
6829	6829	12 to Solar and Energy Storage Initiative Charge provided for
6830	6830	13 in this subsection (c-5) and subsection (i-5) of Section
6831	6831	14 16-108 of the Public Utilities Act, shall not be funded by
6832	6832	15 revenues collected through any of the other funding
6833	6833	16 mechanisms provided for in subsection (c) of this Section,
6834	6834	17 and shall not be subject to the limitation imposed by
6835	6835	18 subsection (c) on charges to retail customers for costs to
6836	6836	19 procure renewable energy resources pursuant to subsection
6837	6837	20 (c), and shall not be subject to any other requirements or
6838	6838	21 limitations of subsection (c).
6839	6839	22 (2) The Agency shall conduct 2 procurement events to
6840	6840	23 select owners of electric generating facilities meeting
6841	6841	24 the eligibility criteria specified in this subsection
6842	6842	25 (c-5) to enter into long-term contracts to sell renewable
6843	6843	26 energy credits to electric utilities serving more than
6844	6844
6845	6845
6846	6846
6847	6847
6848	6848
6849	6849	HB3779 - 190 - LRB104 11172 AAS 21254 b
6850	6850
6851	6851
6852	6852	HB3779- 191 -LRB104 11172 AAS 21254 b HB3779 - 191 - LRB104 11172 AAS 21254 b
6853	6853	HB3779 - 191 - LRB104 11172 AAS 21254 b
6854	6854	1 300,000 retail customers in this State as of January 1,
6855	6855	2 2019. The first procurement event shall be conducted no
6856	6856	3 later than March 31, 2022, unless the Agency elects to
6857	6857	4 delay it, until no later than May 1, 2022, due to its
6858	6858	5 overall volume of work, and shall be to select owners of
6859	6859	6 electric generating facilities located in this State and
6860	6860	7 south of federal Interstate Highway 80 that meet the
6861	6861	8 eligibility criteria specified in this subsection (c-5).
6862	6862	9 The second procurement event shall be conducted no sooner
6863	6863	10 than September 30, 2022 and no later than October 31, 2022
6864	6864	11 and shall be to select owners of electric generating
6865	6865	12 facilities located anywhere in this State that meet the
6866	6866	13 eligibility criteria specified in this subsection (c-5).
6867	6867	14 The Agency shall establish and announce a time period,
6868	6868	15 which shall begin no later than 30 days prior to the
6869	6869	16 scheduled date for the procurement event, during which
6870	6870	17 applicants may submit applications to be selected as
6871	6871	18 suppliers of renewable energy credits pursuant to this
6872	6872	19 subsection (c-5). The eligibility criteria for selection
6873	6873	20 as a supplier of renewable energy credits pursuant to this
6874	6874	21 subsection (c-5) shall be as follows:
6875	6875	22 (A) The applicant owns an electric generating
6876	6876	23 facility located in this State that: (i) as of January
6877	6877	24 1, 2016, burned coal as its primary fuel to generate
6878	6878	25 electricity; and (ii) has, or had prior to retirement,
6879	6879	26 an electric generating capacity of at least 150
6880	6880
6881	6881
6882	6882
6883	6883
6884	6884
6885	6885	HB3779 - 191 - LRB104 11172 AAS 21254 b
6886	6886
6887	6887
6888	6888	HB3779- 192 -LRB104 11172 AAS 21254 b HB3779 - 192 - LRB104 11172 AAS 21254 b
6889	6889	HB3779 - 192 - LRB104 11172 AAS 21254 b
6890	6890	1 megawatts. The electric generating facility can be
6891	6891	2 either: (i) retired as of the date of the procurement
6892	6892	3 event; or (ii) still operating as of the date of the
6893	6893	4 procurement event.
6894	6894	5 (B) The applicant is not (i) an electric
6895	6895	6 cooperative as defined in Section 3-119 of the Public
6896	6896	7 Utilities Act, or (ii) an entity described in
6897	6897	8 subsection (b)(1) of Section 3-105 of the Public
6898	6898	9 Utilities Act, or an association or consortium of or
6899	6899	10 an entity owned by entities described in (i) or (ii);
6900	6900	11 and the coal-fueled electric generating facility was
6901	6901	12 at one time owned, in whole or in part, by a public
6902	6902	13 utility as defined in Section 3-105 of the Public
6903	6903	14 Utilities Act.
6904	6904	15 (C) If participating in the first procurement
6905	6905	16 event, the applicant proposes and commits to construct
6906	6906	17 and operate, at the site, and if necessary for
6907	6907	18 sufficient space on property adjacent to the existing
6908	6908	19 property, at which the electric generating facility
6909	6909	20 identified in paragraph (A) is located: (i) a new
6910	6910	21 renewable energy facility of at least 20 megawatts but
6911	6911	22 no more than 100 megawatts of electric generating
6912	6912	23 capacity, and (ii) an energy storage facility having a
6913	6913	24 storage capacity equal to at least 2 megawatts and at
6914	6914	25 most 10 megawatts. If participating in the second
6915	6915	26 procurement event, the applicant proposes and commits
6916	6916
6917	6917
6918	6918
6919	6919
6920	6920
6921	6921	HB3779 - 192 - LRB104 11172 AAS 21254 b
6922	6922
6923	6923
6924	6924	HB3779- 193 -LRB104 11172 AAS 21254 b HB3779 - 193 - LRB104 11172 AAS 21254 b
6925	6925	HB3779 - 193 - LRB104 11172 AAS 21254 b
6926	6926	1 to construct and operate, at the site, and if
6927	6927	2 necessary for sufficient space on property adjacent to
6928	6928	3 the existing property, at which the electric
6929	6929	4 generating facility identified in paragraph (A) is
6930	6930	5 located: (i) a new renewable energy facility of at
6931	6931	6 least 5 megawatts but no more than 20 megawatts of
6932	6932	7 electric generating capacity, and (ii) an energy
6933	6933	8 storage facility having a storage capacity equal to at
6934	6934	9 least 0.5 megawatts and at most one megawatt.
6935	6935	10 (D) The applicant agrees that the new renewable
6936	6936	11 energy facility and the energy storage facility will
6937	6937	12 be constructed or installed by a qualified entity or
6938	6938	13 entities in compliance with the requirements of
6939	6939	14 subsection (g) of Section 16-128A of the Public
6940	6940	15 Utilities Act and any rules adopted thereunder.
6941	6941	16 (E) The applicant agrees that personnel operating
6942	6942	17 the new renewable energy facility and the energy
6943	6943	18 storage facility will have the requisite skills,
6944	6944	19 knowledge, training, experience, and competence, which
6945	6945	20 may be demonstrated by completion or current
6946	6946	21 participation and ultimate completion by employees of
6947	6947	22 an accredited or otherwise recognized apprenticeship
6948	6948	23 program for the employee's particular craft, trade, or
6949	6949	24 skill, including through training and education
6950	6950	25 courses and opportunities offered by the owner to
6951	6951	26 employees of the coal-fueled electric generating
6952	6952
6953	6953
6954	6954
6955	6955
6956	6956
6957	6957	HB3779 - 193 - LRB104 11172 AAS 21254 b
6958	6958
6959	6959
6960	6960	HB3779- 194 -LRB104 11172 AAS 21254 b HB3779 - 194 - LRB104 11172 AAS 21254 b
6961	6961	HB3779 - 194 - LRB104 11172 AAS 21254 b
6962	6962	1 facility or by previous employment experience
6963	6963	2 performing the employee's particular work skill or
6964	6964	3 function.
6965	6965	4 (F) The applicant commits that not less than the
6966	6966	5 prevailing wage, as determined pursuant to the
6967	6967	6 Prevailing Wage Act, will be paid to the applicant's
6968	6968	7 employees engaged in construction activities
6969	6969	8 associated with the new renewable energy facility and
6970	6970	9 the new energy storage facility and to the employees
6971	6971	10 of applicant's contractors engaged in construction
6972	6972	11 activities associated with the new renewable energy
6973	6973	12 facility and the new energy storage facility, and
6974	6974	13 that, on or before the commercial operation date of
6975	6975	14 the new renewable energy facility, the applicant shall
6976	6976	15 file a report with the Agency certifying that the
6977	6977	16 requirements of this subparagraph (F) have been met.
6978	6978	17 (G) The applicant commits that if selected, it
6979	6979	18 will negotiate a project labor agreement for the
6980	6980	19 construction of the new renewable energy facility and
6981	6981	20 associated energy storage facility that includes
6982	6982	21 provisions requiring the parties to the agreement to
6983	6983	22 work together to establish diversity threshold
6984	6984	23 requirements and to ensure best efforts to meet
6985	6985	24 diversity targets, improve diversity at the applicable
6986	6986	25 job site, create diverse apprenticeship opportunities,
6987	6987	26 and create opportunities to employ former coal-fired
6988	6988
6989	6989
6990	6990
6991	6991
6992	6992
6993	6993	HB3779 - 194 - LRB104 11172 AAS 21254 b
6994	6994
6995	6995
6996	6996	HB3779- 195 -LRB104 11172 AAS 21254 b HB3779 - 195 - LRB104 11172 AAS 21254 b
6997	6997	HB3779 - 195 - LRB104 11172 AAS 21254 b
6998	6998	1 power plant workers.
6999	6999	2 (H) The applicant commits to enter into a contract
7000	7000	3 or contracts for the applicable duration to provide
7001	7001	4 specified numbers of renewable energy credits each
7002	7002	5 year from the new renewable energy facility to
7003	7003	6 electric utilities that served more than 300,000
7004	7004	7 retail customers in this State as of January 1, 2019,
7005	7005	8 at a price of $30 per renewable energy credit. The
7006	7006	9 price per renewable energy credit shall be fixed at
7007	7007	10 $30 for the applicable duration and the renewable
7008	7008	11 energy credits shall not be indexed renewable energy
7009	7009	12 credits as provided for in item (v) of subparagraph
7010	7010	13 (G) of paragraph (1) of subsection (c) of Section 1-75
7011	7011	14 of this Act. The applicable duration of each contract
7012	7012	15 shall be 20 years, unless the applicant is physically
7013	7013	16 interconnected to the PJM Interconnection, LLC
7014	7014	17 transmission grid and had a generating capacity of at
7015	7015	18 least 1,200 megawatts as of January 1, 2021, in which
7016	7016	19 case the applicable duration of the contract shall be
7017	7017	20 15 years.
7018	7018	21 (I) The applicant's application is certified by an
7019	7019	22 officer of the applicant and by an officer of the
7020	7020	23 applicant's ultimate parent company, if any.
7021	7021	24 (3) An applicant may submit applications to contract
7022	7022	25 to supply renewable energy credits from more than one new
7023	7023	26 renewable energy facility to be constructed at or adjacent
7024	7024
7025	7025
7026	7026
7027	7027
7028	7028
7029	7029	HB3779 - 195 - LRB104 11172 AAS 21254 b
7030	7030
7031	7031
7032	7032	HB3779- 196 -LRB104 11172 AAS 21254 b HB3779 - 196 - LRB104 11172 AAS 21254 b
7033	7033	HB3779 - 196 - LRB104 11172 AAS 21254 b
7034	7034	1 to one or more qualifying electric generating facilities
7035	7035	2 owned by the applicant. The Agency may select new
7036	7036	3 renewable energy facilities to be located at or adjacent
7037	7037	4 to the sites of more than one qualifying electric
7038	7038	5 generation facility owned by an applicant to contract with
7039	7039	6 electric utilities to supply renewable energy credits from
7040	7040	7 such facilities.
7041	7041	8 (4) The Agency shall assess fees to each applicant to
7042	7042	9 recover the Agency's costs incurred in receiving and
7043	7043	10 evaluating applications, conducting the procurement event,
7044	7044	11 developing contracts for sale, delivery and purchase of
7045	7045	12 renewable energy credits, and monitoring the
7046	7046	13 administration of such contracts, as provided for in this
7047	7047	14 subsection (c-5), including fees paid to a procurement
7048	7048	15 administrator retained by the Agency for one or more of
7049	7049	16 these purposes.
7050	7050	17 (5) The Agency shall select the applicants and the new
7051	7051	18 renewable energy facilities to contract with electric
7052	7052	19 utilities to supply renewable energy credits in accordance
7053	7053	20 with this subsection (c-5). In the first procurement
7054	7054	21 event, the Agency shall select applicants and new
7055	7055	22 renewable energy facilities to supply renewable energy
7056	7056	23 credits, at a price of $30 per renewable energy credit,
7057	7057	24 aggregating to no less than 400,000 renewable energy
7058	7058	25 credits per year for the applicable duration, assuming
7059	7059	26 sufficient qualifying applications to supply, in the
7060	7060
7061	7061
7062	7062
7063	7063
7064	7064
7065	7065	HB3779 - 196 - LRB104 11172 AAS 21254 b
7066	7066
7067	7067
7068	7068	HB3779- 197 -LRB104 11172 AAS 21254 b HB3779 - 197 - LRB104 11172 AAS 21254 b
7069	7069	HB3779 - 197 - LRB104 11172 AAS 21254 b
7070	7070	1 aggregate, at least that amount of renewable energy
7071	7071	2 credits per year; and not more than 580,000 renewable
7072	7072	3 energy credits per year for the applicable duration. In
7073	7073	4 the second procurement event, the Agency shall select
7074	7074	5 applicants and new renewable energy facilities to supply
7075	7075	6 renewable energy credits, at a price of $30 per renewable
7076	7076	7 energy credit, aggregating to no more than 625,000
7077	7077	8 renewable energy credits per year less the amount of
7078	7078	9 renewable energy credits each year contracted for as a
7079	7079	10 result of the first procurement event, for the applicable
7080	7080	11 durations. The number of renewable energy credits to be
7081	7081	12 procured as specified in this paragraph (5) shall not be
7082	7082	13 reduced based on renewable energy credits procured in the
7083	7083	14 self-direct renewable energy credit compliance program
7084	7084	15 established pursuant to subparagraph (R) of paragraph (1)
7085	7085	16 of subsection (c) of Section 1-75.
7086	7086	17 (6) The obligation to purchase renewable energy
7087	7087	18 credits from the applicants and their new renewable energy
7088	7088	19 facilities selected by the Agency shall be allocated to
7089	7089	20 the electric utilities based on their respective
7090	7090	21 percentages of kilowatthours delivered to delivery
7091	7091	22 services customers to the aggregate kilowatthour
7092	7092	23 deliveries by the electric utilities to delivery services
7093	7093	24 customers for the year ended December 31, 2021. In order
7094	7094	25 to achieve these allocation percentages between or among
7095	7095	26 the electric utilities, the Agency shall require each
7096	7096
7097	7097
7098	7098
7099	7099
7100	7100
7101	7101	HB3779 - 197 - LRB104 11172 AAS 21254 b
7102	7102
7103	7103
7104	7104	HB3779- 198 -LRB104 11172 AAS 21254 b HB3779 - 198 - LRB104 11172 AAS 21254 b
7105	7105	HB3779 - 198 - LRB104 11172 AAS 21254 b
7106	7106	1 applicant that is selected in the procurement event to
7107	7107	2 enter into a contract with each electric utility for the
7108	7108	3 sale and purchase of renewable energy credits from each
7109	7109	4 new renewable energy facility to be constructed and
7110	7110	5 operated by the applicant, with the sale and purchase
7111	7111	6 obligations under the contracts to aggregate to the total
7112	7112	7 number of renewable energy credits per year to be supplied
7113	7113	8 by the applicant from the new renewable energy facility.
7114	7114	9 (7) The Agency shall submit its proposed selection of
7115	7115	10 applicants, new renewable energy facilities to be
7116	7116	11 constructed, and renewable energy credit amounts for each
7117	7117	12 procurement event to the Commission for approval. The
7118	7118	13 Commission shall, within 2 business days after receipt of
7119	7119	14 the Agency's proposed selections, approve the proposed
7120	7120	15 selections if it determines that the applicants and the
7121	7121	16 new renewable energy facilities to be constructed meet the
7122	7122	17 selection criteria set forth in this subsection (c-5) and
7123	7123	18 that the Agency seeks approval for contracts of applicable
7124	7124	19 durations aggregating to no more than the maximum amount
7125	7125	20 of renewable energy credits per year authorized by this
7126	7126	21 subsection (c-5) for the procurement event, at a price of
7127	7127	22 $30 per renewable energy credit.
7128	7128	23 (8) The Agency, in conjunction with its procurement
7129	7129	24 administrator if one is retained, the electric utilities,
7130	7130	25 and potential applicants for contracts to produce and
7131	7131	26 supply renewable energy credits pursuant to this
7132	7132
7133	7133
7134	7134
7135	7135
7136	7136
7137	7137	HB3779 - 198 - LRB104 11172 AAS 21254 b
7138	7138
7139	7139
7140	7140	HB3779- 199 -LRB104 11172 AAS 21254 b HB3779 - 199 - LRB104 11172 AAS 21254 b
7141	7141	HB3779 - 199 - LRB104 11172 AAS 21254 b
7142	7142	1 subsection (c-5), shall develop a standard form contract
7143	7143	2 for the sale, delivery and purchase of renewable energy
7144	7144	3 credits pursuant to this subsection (c-5). Each contract
7145	7145	4 resulting from the first procurement event shall allow for
7146	7146	5 a commercial operation date for the new renewable energy
7147	7147	6 facility of either June 1, 2023 or June 1, 2024, with such
7148	7148	7 dates subject to adjustment as provided in this paragraph.
7149	7149	8 Each contract resulting from the second procurement event
7150	7150	9 shall provide for a commercial operation date on June 1
7151	7151	10 next occurring up to 48 months after execution of the
7152	7152	11 contract. Each contract shall provide that the owner shall
7153	7153	12 receive payments for renewable energy credits for the
7154	7154	13 applicable durations beginning with the commercial
7155	7155	14 operation date of the new renewable energy facility. The
7156	7156	15 form contract shall provide for adjustments to the
7157	7157	16 commercial operation and payment start dates as needed due
7158	7158	17 to any delays in completing the procurement and
7159	7159	18 contracting processes, in finalizing interconnection
7160	7160	19 agreements and installing interconnection facilities, and
7161	7161	20 in obtaining other necessary governmental permits and
7162	7162	21 approvals. The form contract shall be, to the maximum
7163	7163	22 extent possible, consistent with standard electric
7164	7164	23 industry contracts for sale, delivery, and purchase of
7165	7165	24 renewable energy credits while taking into account the
7166	7166	25 specific requirements of this subsection (c-5). The form
7167	7167	26 contract shall provide for over-delivery and
7168	7168
7169	7169
7170	7170
7171	7171
7172	7172
7173	7173	HB3779 - 199 - LRB104 11172 AAS 21254 b
7174	7174
7175	7175
7176	7176	HB3779- 200 -LRB104 11172 AAS 21254 b HB3779 - 200 - LRB104 11172 AAS 21254 b
7177	7177	HB3779 - 200 - LRB104 11172 AAS 21254 b
7178	7178	1 under-delivery of renewable energy credits within
7179	7179	2 reasonable ranges during each 12-month period and penalty,
7180	7180	3 default, and enforcement provisions for failure of the
7181	7181	4 selling party to deliver renewable energy credits as
7182	7182	5 specified in the contract and to comply with the
7183	7183	6 requirements of this subsection (c-5). The standard form
7184	7184	7 contract shall specify that all renewable energy credits
7185	7185	8 delivered to the electric utility pursuant to the contract
7186	7186	9 shall be retired. The Agency shall make the proposed
7187	7187	10 contracts available for a reasonable period for comment by
7188	7188	11 potential applicants, and shall publish the final form
7189	7189	12 contract at least 30 days before the date of the first
7190	7190	13 procurement event.
7191	7191	14 (9) Coal to Solar and Energy Storage Initiative
7192	7192	15 Charge.
7193	7193	16 (A) By no later than July 1, 2022, each electric
7194	7194	17 utility that served more than 300,000 retail customers
7195	7195	18 in this State as of January 1, 2019 shall file a tariff
7196	7196	19 with the Commission for the billing and collection of
7197	7197	20 a Coal to Solar and Energy Storage Initiative Charge
7198	7198	21 in accordance with subsection (i-5) of Section 16-108
7199	7199	22 of the Public Utilities Act, with such tariff to be
7200	7200	23 effective, following review and approval or
7201	7201	24 modification by the Commission, beginning January 1,
7202	7202	25 2023. The tariff shall provide for the calculation and
7203	7203	26 setting of the electric utility's Coal to Solar and
7204	7204
7205	7205
7206	7206
7207	7207
7208	7208
7209	7209	HB3779 - 200 - LRB104 11172 AAS 21254 b
7210	7210
7211	7211
7212	7212	HB3779- 201 -LRB104 11172 AAS 21254 b HB3779 - 201 - LRB104 11172 AAS 21254 b
7213	7213	HB3779 - 201 - LRB104 11172 AAS 21254 b
7214	7214	1 Energy Storage Initiative Charge to collect revenues
7215	7215	2 estimated to be sufficient, in the aggregate, (i) to
7216	7216	3 enable the electric utility to pay for the renewable
7217	7217	4 energy credits it has contracted to purchase in the
7218	7218	5 delivery year beginning June 1, 2023 and each delivery
7219	7219	6 year thereafter from new renewable energy facilities
7220	7220	7 located at the sites of qualifying electric generating
7221	7221	8 facilities, and (ii) to fund the grant payments to be
7222	7222	9 made in each delivery year by the Department of
7223	7223	10 Commerce and Economic Opportunity, or any successor
7224	7224	11 department or agency, which shall be referred to in
7225	7225	12 this subsection (c-5) as the Department, pursuant to
7226	7226	13 paragraph (10) of this subsection (c-5). The electric
7227	7227	14 utility's tariff shall provide for the billing and
7228	7228	15 collection of the Coal to Solar and Energy Storage
7229	7229	16 Initiative Charge on each kilowatthour of electricity
7230	7230	17 delivered to its delivery services customers within
7231	7231	18 its service territory and shall provide for an annual
7232	7232	19 reconciliation of revenues collected with actual
7233	7233	20 costs, in accordance with subsection (i-5) of Section
7234	7234	21 16-108 of the Public Utilities Act.
7235	7235	22 (B) Each electric utility shall remit on a monthly
7236	7236	23 basis to the State Treasurer, for deposit in the Coal
7237	7237	24 to Solar and Energy Storage Initiative Fund provided
7238	7238	25 for in this subsection (c-5), the electric utility's
7239	7239	26 collections of the Coal to Solar and Energy Storage
7240	7240
7241	7241
7242	7242
7243	7243
7244	7244
7245	7245	HB3779 - 201 - LRB104 11172 AAS 21254 b
7246	7246
7247	7247
7248	7248	HB3779- 202 -LRB104 11172 AAS 21254 b HB3779 - 202 - LRB104 11172 AAS 21254 b
7249	7249	HB3779 - 202 - LRB104 11172 AAS 21254 b
7250	7250	1 Initiative Charge in the amount estimated to be needed
7251	7251	2 by the Department for grant payments pursuant to grant
7252	7252	3 contracts entered into by the Department pursuant to
7253	7253	4 paragraph (10) of this subsection (c-5).
7254	7254	5 (10) Coal to Solar and Energy Storage Initiative Fund.
7255	7255	6 (A) The Coal to Solar and Energy Storage
7256	7256	7 Initiative Fund is established as a special fund in
7257	7257	8 the State treasury. The Coal to Solar and Energy
7258	7258	9 Storage Initiative Fund is authorized to receive, by
7259	7259	10 statutory deposit, that portion specified in item (B)
7260	7260	11 of paragraph (9) of this subsection (c-5) of moneys
7261	7261	12 collected by electric utilities through imposition of
7262	7262	13 the Coal to Solar and Energy Storage Initiative Charge
7263	7263	14 required by this subsection (c-5). The Coal to Solar
7264	7264	15 and Energy Storage Initiative Fund shall be
7265	7265	16 administered by the Department to provide grants to
7266	7266	17 support the installation and operation of energy
7267	7267	18 storage facilities at the sites of qualifying electric
7268	7268	19 generating facilities meeting the criteria specified
7269	7269	20 in this paragraph (10).
7270	7270	21 (B) The Coal to Solar and Energy Storage
7271	7271	22 Initiative Fund shall not be subject to sweeps,
7272	7272	23 administrative charges, or chargebacks, including, but
7273	7273	24 not limited to, those authorized under Section 8h of
7274	7274	25 the State Finance Act, that would in any way result in
7275	7275	26 the transfer of those funds from the Coal to Solar and
7276	7276
7277	7277
7278	7278
7279	7279
7280	7280
7281	7281	HB3779 - 202 - LRB104 11172 AAS 21254 b
7282	7282
7283	7283
7284	7284	HB3779- 203 -LRB104 11172 AAS 21254 b HB3779 - 203 - LRB104 11172 AAS 21254 b
7285	7285	HB3779 - 203 - LRB104 11172 AAS 21254 b
7286	7286	1 Energy Storage Initiative Fund to any other fund of
7287	7287	2 this State or in having any such funds utilized for any
7288	7288	3 purpose other than the express purposes set forth in
7289	7289	4 this paragraph (10).
7290	7290	5 (C) The Department shall utilize up to
7291	7291	6 $280,500,000 in the Coal to Solar and Energy Storage
7292	7292	7 Initiative Fund for grants, assuming sufficient
7293	7293	8 qualifying applicants, to support installation of
7294	7294	9 energy storage facilities at the sites of up to 3
7295	7295	10 qualifying electric generating facilities located in
7296	7296	11 the Midcontinent Independent System Operator, Inc.,
7297	7297	12 region in Illinois and the sites of up to 2 qualifying
7298	7298	13 electric generating facilities located in the PJM
7299	7299	14 Interconnection, LLC region in Illinois that meet the
7300	7300	15 criteria set forth in this subparagraph (C). The
7301	7301	16 criteria for receipt of a grant pursuant to this
7302	7302	17 subparagraph (C) are as follows:
7303	7303	18 (1) the electric generating facility at the
7304	7304	19 site has, or had prior to retirement, an electric
7305	7305	20 generating capacity of at least 150 megawatts;
7306	7306	21 (2) the electric generating facility burns (or
7307	7307	22 burned prior to retirement) coal as its primary
7308	7308	23 source of fuel;
7309	7309	24 (3) if the electric generating facility is
7310	7310	25 retired, it was retired subsequent to January 1,
7311	7311	26 2016;
7312	7312
7313	7313
7314	7314
7315	7315
7316	7316
7317	7317	HB3779 - 203 - LRB104 11172 AAS 21254 b
7318	7318
7319	7319
7320	7320	HB3779- 204 -LRB104 11172 AAS 21254 b HB3779 - 204 - LRB104 11172 AAS 21254 b
7321	7321	HB3779 - 204 - LRB104 11172 AAS 21254 b
7322	7322	1 (4) the owner of the electric generating
7323	7323	2 facility has not been selected by the Agency
7324	7324	3 pursuant to this subsection (c-5) of this Section
7325	7325	4 to enter into a contract to sell renewable energy
7326	7326	5 credits to one or more electric utilities from a
7327	7327	6 new renewable energy facility located or to be
7328	7328	7 located at or adjacent to the site at which the
7329	7329	8 electric generating facility is located;
7330	7330	9 (5) the electric generating facility located
7331	7331	10 at the site was at one time owned, in whole or in
7332	7332	11 part, by a public utility as defined in Section
7333	7333	12 3-105 of the Public Utilities Act;
7334	7334	13 (6) the electric generating facility at the
7335	7335	14 site is not owned by (i) an electric cooperative
7336	7336	15 as defined in Section 3-119 of the Public
7337	7337	16 Utilities Act, or (ii) an entity described in
7338	7338	17 subsection (b)(1) of Section 3-105 of the Public
7339	7339	18 Utilities Act, or an association or consortium of
7340	7340	19 or an entity owned by entities described in items
7341	7341	20 (i) or (ii);
7342	7342	21 (7) the proposed energy storage facility at
7343	7343	22 the site will have energy storage capacity of at
7344	7344	23 least 37 megawatts;
7345	7345	24 (8) the owner commits to place the energy
7346	7346	25 storage facility into commercial operation on
7347	7347	26 either June 1, 2023, June 1, 2024, or June 1, 2025,
7348	7348
7349	7349
7350	7350
7351	7351
7352	7352
7353	7353	HB3779 - 204 - LRB104 11172 AAS 21254 b
7354	7354
7355	7355
7356	7356	HB3779- 205 -LRB104 11172 AAS 21254 b HB3779 - 205 - LRB104 11172 AAS 21254 b
7357	7357	HB3779 - 205 - LRB104 11172 AAS 21254 b
7358	7358	1 with such date subject to adjustment as needed due
7359	7359	2 to any delays in completing the grant contracting
7360	7360	3 process, in finalizing interconnection agreements
7361	7361	4 and in installing interconnection facilities, and
7362	7362	5 in obtaining necessary governmental permits and
7363	7363	6 approvals;
7364	7364	7 (9) the owner agrees that the new energy
7365	7365	8 storage facility will be constructed or installed
7366	7366	9 by a qualified entity or entities consistent with
7367	7367	10 the requirements of subsection (g) of Section
7368	7368	11 16-128A of the Public Utilities Act and any rules
7369	7369	12 adopted under that Section;
7370	7370	13 (10) the owner agrees that personnel operating
7371	7371	14 the energy storage facility will have the
7372	7372	15 requisite skills, knowledge, training, experience,
7373	7373	16 and competence, which may be demonstrated by
7374	7374	17 completion or current participation and ultimate
7375	7375	18 completion by employees of an accredited or
7376	7376	19 otherwise recognized apprenticeship program for
7377	7377	20 the employee's particular craft, trade, or skill,
7378	7378	21 including through training and education courses
7379	7379	22 and opportunities offered by the owner to
7380	7380	23 employees of the coal-fueled electric generating
7381	7381	24 facility or by previous employment experience
7382	7382	25 performing the employee's particular work skill or
7383	7383	26 function;
7384	7384
7385	7385
7386	7386
7387	7387
7388	7388
7389	7389	HB3779 - 205 - LRB104 11172 AAS 21254 b
7390	7390
7391	7391
7392	7392	HB3779- 206 -LRB104 11172 AAS 21254 b HB3779 - 206 - LRB104 11172 AAS 21254 b
7393	7393	HB3779 - 206 - LRB104 11172 AAS 21254 b
7394	7394	1 (11) the owner commits that not less than the
7395	7395	2 prevailing wage, as determined pursuant to the
7396	7396	3 Prevailing Wage Act, will be paid to the owner's
7397	7397	4 employees engaged in construction activities
7398	7398	5 associated with the new energy storage facility
7399	7399	6 and to the employees of the owner's contractors
7400	7400	7 engaged in construction activities associated with
7401	7401	8 the new energy storage facility, and that, on or
7402	7402	9 before the commercial operation date of the new
7403	7403	10 energy storage facility, the owner shall file a
7404	7404	11 report with the Department certifying that the
7405	7405	12 requirements of this subparagraph (11) have been
7406	7406	13 met; and
7407	7407	14 (12) the owner commits that if selected to
7408	7408	15 receive a grant, it will negotiate a project labor
7409	7409	16 agreement for the construction of the new energy
7410	7410	17 storage facility that includes provisions
7411	7411	18 requiring the parties to the agreement to work
7412	7412	19 together to establish diversity threshold
7413	7413	20 requirements and to ensure best efforts to meet
7414	7414	21 diversity targets, improve diversity at the
7415	7415	22 applicable job site, create diverse apprenticeship
7416	7416	23 opportunities, and create opportunities to employ
7417	7417	24 former coal-fired power plant workers.
7418	7418	25 The Department shall accept applications for this
7419	7419	26 grant program until March 31, 2022 and shall announce
7420	7420
7421	7421
7422	7422
7423	7423
7424	7424
7425	7425	HB3779 - 206 - LRB104 11172 AAS 21254 b
7426	7426
7427	7427
7428	7428	HB3779- 207 -LRB104 11172 AAS 21254 b HB3779 - 207 - LRB104 11172 AAS 21254 b
7429	7429	HB3779 - 207 - LRB104 11172 AAS 21254 b
7430	7430	1 the award of grants no later than June 1, 2022. The
7431	7431	2 Department shall make the grant payments to a
7432	7432	3 recipient in equal annual amounts for 10 years
7433	7433	4 following the date the energy storage facility is
7434	7434	5 placed into commercial operation. The annual grant
7435	7435	6 payments to a qualifying energy storage facility shall
7436	7436	7 be $110,000 per megawatt of energy storage capacity,
7437	7437	8 with total annual grant payments pursuant to this
7438	7438	9 subparagraph (C) for qualifying energy storage
7439	7439	10 facilities not to exceed $28,050,000 in any year.
7440	7440	11 (D) Grants of funding for energy storage
7441	7441	12 facilities pursuant to subparagraph (C) of this
7442	7442	13 paragraph (10), from the Coal to Solar and Energy
7443	7443	14 Storage Initiative Fund, shall be memorialized in
7444	7444	15 grant contracts between the Department and the
7445	7445	16 recipient. The grant contracts shall specify the date
7446	7446	17 or dates in each year on which the annual grant
7447	7447	18 payments shall be paid.
7448	7448	19 (E) All disbursements from the Coal to Solar and
7449	7449	20 Energy Storage Initiative Fund shall be made only upon
7450	7450	21 warrants of the Comptroller drawn upon the Treasurer
7451	7451	22 as custodian of the Fund upon vouchers signed by the
7452	7452	23 Director of the Department or by the person or persons
7453	7453	24 designated by the Director of the Department for that
7454	7454	25 purpose. The Comptroller is authorized to draw the
7455	7455	26 warrants upon vouchers so signed. The Treasurer shall
7456	7456
7457	7457
7458	7458
7459	7459
7460	7460
7461	7461	HB3779 - 207 - LRB104 11172 AAS 21254 b
7462	7462
7463	7463
7464	7464	HB3779- 208 -LRB104 11172 AAS 21254 b HB3779 - 208 - LRB104 11172 AAS 21254 b
7465	7465	HB3779 - 208 - LRB104 11172 AAS 21254 b
7466	7466	1 accept all written warrants so signed and shall be
7467	7467	2 released from liability for all payments made on those
7468	7468	3 warrants.
7469	7469	4 (11) Diversity, equity, and inclusion plans.
7470	7470	5 (A) Each applicant selected in a procurement event
7471	7471	6 to contract to supply renewable energy credits in
7472	7472	7 accordance with this subsection (c-5) and each owner
7473	7473	8 selected by the Department to receive a grant or
7474	7474	9 grants to support the construction and operation of a
7475	7475	10 new energy storage facility or facilities in
7476	7476	11 accordance with this subsection (c-5) shall, within 60
7477	7477	12 days following the Commission's approval of the
7478	7478	13 applicant to contract to supply renewable energy
7479	7479	14 credits or within 60 days following execution of a
7480	7480	15 grant contract with the Department, as applicable,
7481	7481	16 submit to the Commission a diversity, equity, and
7482	7482	17 inclusion plan setting forth the applicant's or
7483	7483	18 owner's numeric goals for the diversity composition of
7484	7484	19 its supplier entities for the new renewable energy
7485	7485	20 facility or new energy storage facility, as
7486	7486	21 applicable, which shall be referred to for purposes of
7487	7487	22 this paragraph (11) as the project, and the
7488	7488	23 applicant's or owner's action plan and schedule for
7489	7489	24 achieving those goals.
7490	7490	25 (B) For purposes of this paragraph (11), diversity
7491	7491	26 composition shall be based on the percentage, which
7492	7492
7493	7493
7494	7494
7495	7495
7496	7496
7497	7497	HB3779 - 208 - LRB104 11172 AAS 21254 b
7498	7498
7499	7499
7500	7500	HB3779- 209 -LRB104 11172 AAS 21254 b HB3779 - 209 - LRB104 11172 AAS 21254 b
7501	7501	HB3779 - 209 - LRB104 11172 AAS 21254 b
7502	7502	1 shall be a minimum of 25%, of eligible expenditures
7503	7503	2 for contract awards for materials and services (which
7504	7504	3 shall be defined in the plan) to business enterprises
7505	7505	4 owned by minority persons, women, or persons with
7506	7506	5 disabilities as defined in Section 2 of the Business
7507	7507	6 Enterprise for Minorities, Women, and Persons with
7508	7508	7 Disabilities Act, to LGBTQ business enterprises, to
7509	7509	8 veteran-owned business enterprises, and to business
7510	7510	9 enterprises located in environmental justice
7511	7511	10 communities. The diversity composition goals of the
7512	7512	11 plan may include eligible expenditures in areas for
7513	7513	12 vendor or supplier opportunities in addition to
7514	7514	13 development and construction of the project, and may
7515	7515	14 exclude from eligible expenditures materials and
7516	7516	15 services with limited market availability, limited
7517	7517	16 production and availability from suppliers in the
7518	7518	17 United States, such as solar panels and storage
7519	7519	18 batteries, and material and services that are subject
7520	7520	19 to critical energy infrastructure or cybersecurity
7521	7521	20 requirements or restrictions. The plan may provide
7522	7522	21 that the diversity composition goals may be met
7523	7523	22 through Tier 1 Direct or Tier 2 subcontracting
7524	7524	23 expenditures or a combination thereof for the project.
7525	7525	24 (C) The plan shall provide for, but not be limited
7526	7526	25 to: (i) internal initiatives, including multi-tier
7527	7527	26 initiatives, by the applicant or owner, or by its
7528	7528
7529	7529
7530	7530
7531	7531
7532	7532
7533	7533	HB3779 - 209 - LRB104 11172 AAS 21254 b
7534	7534
7535	7535
7536	7536	HB3779- 210 -LRB104 11172 AAS 21254 b HB3779 - 210 - LRB104 11172 AAS 21254 b
7537	7537	HB3779 - 210 - LRB104 11172 AAS 21254 b
7538	7538	1 engineering, procurement and construction contractor
7539	7539	2 if one is used for the project, which for purposes of
7540	7540	3 this paragraph (11) shall be referred to as the EPC
7541	7541	4 contractor, to enable diverse businesses to be
7542	7542	5 considered fairly for selection to provide materials
7543	7543	6 and services; (ii) requirements for the applicant or
7544	7544	7 owner or its EPC contractor to proactively solicit and
7545	7545	8 utilize diverse businesses to provide materials and
7546	7546	9 services; and (iii) requirements for the applicant or
7547	7547	10 owner or its EPC contractor to hire a diverse
7548	7548	11 workforce for the project. The plan shall include a
7549	7549	12 description of the applicant's or owner's diversity
7550	7550	13 recruiting efforts both for the project and for other
7551	7551	14 areas of the applicant's or owner's business
7552	7552	15 operations. The plan shall provide for the imposition
7553	7553	16 of financial penalties on the applicant's or owner's
7554	7554	17 EPC contractor for failure to exercise best efforts to
7555	7555	18 comply with and execute the EPC contractor's diversity
7556	7556	19 obligations under the plan. The plan may provide for
7557	7557	20 the applicant or owner to set aside a portion of the
7558	7558	21 work on the project to serve as an incubation program
7559	7559	22 for qualified businesses, as specified in the plan,
7560	7560	23 owned by minority persons, women, persons with
7561	7561	24 disabilities, LGBTQ persons, and veterans, and
7562	7562	25 businesses located in environmental justice
7563	7563	26 communities, seeking to enter the renewable energy
7564	7564
7565	7565
7566	7566
7567	7567
7568	7568
7569	7569	HB3779 - 210 - LRB104 11172 AAS 21254 b
7570	7570
7571	7571
7572	7572	HB3779- 211 -LRB104 11172 AAS 21254 b HB3779 - 211 - LRB104 11172 AAS 21254 b
7573	7573	HB3779 - 211 - LRB104 11172 AAS 21254 b
7574	7574	1 industry.
7575	7575	2 (D) The applicant or owner may submit a revised or
7576	7576	3 updated plan to the Commission from time to time as
7577	7577	4 circumstances warrant. The applicant or owner shall
7578	7578	5 file annual reports with the Commission detailing the
7579	7579	6 applicant's or owner's progress in implementing its
7580	7580	7 plan and achieving its goals and any modifications the
7581	7581	8 applicant or owner has made to its plan to better
7582	7582	9 achieve its diversity, equity and inclusion goals. The
7583	7583	10 applicant or owner shall file a final report on the
7584	7584	11 fifth June 1 following the commercial operation date
7585	7585	12 of the new renewable energy resource or new energy
7586	7586	13 storage facility, but the applicant or owner shall
7587	7587	14 thereafter continue to be subject to applicable
7588	7588	15 reporting requirements of Section 5-117 of the Public
7589	7589	16 Utilities Act.
7590	7590	17 (c-10) Equity accountability system. It is the purpose of
7591	7591	18 this subsection (c-10) to create an equity accountability
7592	7592	19 system, which includes the minimum equity standards for all
7593	7593	20 renewable energy procurements, the equity category of the
7594	7594	21 Adjustable Block Program, and the equity prioritization for
7595	7595	22 noncompetitive procurements, that is successful in advancing
7596	7596	23 priority access to the clean energy economy for businesses and
7597	7597	24 workers from communities that have been excluded from economic
7598	7598	25 opportunities in the energy sector, have been subject to
7599	7599	26 disproportionate levels of pollution, and have
7600	7600
7601	7601
7602	7602
7603	7603
7604	7604
7605	7605	HB3779 - 211 - LRB104 11172 AAS 21254 b
7606	7606
7607	7607
7608	7608	HB3779- 212 -LRB104 11172 AAS 21254 b HB3779 - 212 - LRB104 11172 AAS 21254 b
7609	7609	HB3779 - 212 - LRB104 11172 AAS 21254 b
7610	7610	1 disproportionately experienced negative public health
7611	7611	2 outcomes. Further, it is the purpose of this subsection to
7612	7612	3 ensure that this equity accountability system is successful in
7613	7613	4 advancing equity across Illinois by providing access to the
7614	7614	5 clean energy economy for businesses and workers from
7615	7615	6 communities that have been historically excluded from economic
7616	7616	7 opportunities in the energy sector, have been subject to
7617	7617	8 disproportionate levels of pollution, and have
7618	7618	9 disproportionately experienced negative public health
7619	7619	10 outcomes.
7620	7620	11 (1) Minimum equity standards. The Agency shall create
7621	7621	12 programs with the purpose of increasing access to and
7622	7622	13 development of equity eligible contractors, who are prime
7623	7623	14 contractors and subcontractors, across all of the programs
7624	7624	15 it manages. All applications for renewable energy credit
7625	7625	16 procurements shall comply with specific minimum equity
7626	7626	17 commitments. Starting in the delivery year immediately
7627	7627	18 following the next long-term renewable resources
7628	7628	19 procurement plan, at least 10% of the project workforce
7629	7629	20 for each entity participating in a procurement program
7630	7630	21 outlined in this subsection (c-10) must be done by equity
7631	7631	22 eligible persons or equity eligible contractors. The
7632	7632	23 Agency shall increase the minimum percentage each delivery
7633	7633	24 year thereafter by increments that ensure a statewide
7634	7634	25 average of 30% of the project workforce for each entity
7635	7635	26 participating in a procurement program is done by equity
7636	7636
7637	7637
7638	7638
7639	7639
7640	7640
7641	7641	HB3779 - 212 - LRB104 11172 AAS 21254 b
7642	7642
7643	7643
7644	7644	HB3779- 213 -LRB104 11172 AAS 21254 b HB3779 - 213 - LRB104 11172 AAS 21254 b
7645	7645	HB3779 - 213 - LRB104 11172 AAS 21254 b
7646	7646	1 eligible persons or equity eligible contractors by 2030.
7647	7647	2 The Agency shall propose a schedule of percentage
7648	7648	3 increases to the minimum equity standards in its draft
7649	7649	4 revised renewable energy resources procurement plan
7650	7650	5 submitted to the Commission for approval pursuant to
7651	7651	6 paragraph (5) of subsection (b) of Section 16-111.5 of the
7652	7652	7 Public Utilities Act. In determining these annual
7653	7653	8 increases, the Agency shall have the discretion to
7654	7654	9 establish different minimum equity standards for different
7655	7655	10 types of procurements and different regions of the State
7656	7656	11 if the Agency finds that doing so will further the
7657	7657	12 purposes of this subsection (c-10). The proposed schedule
7658	7658	13 of annual increases shall be revisited and updated on an
7659	7659	14 annual basis. Revisions shall be developed with
7660	7660	15 stakeholder input, including from equity eligible persons,
7661	7661	16 equity eligible contractors, clean energy industry
7662	7662	17 representatives, and community-based organizations that
7663	7663	18 work with such persons and contractors.
7664	7664	19 (A) At the start of each delivery year, the Agency
7665	7665	20 shall require a compliance plan from each entity
7666	7666	21 participating in a procurement program of subsection
7667	7667	22 (c) of this Section that demonstrates how they will
7668	7668	23 achieve compliance with the minimum equity standard
7669	7669	24 percentage for work completed in that delivery year.
7670	7670	25 If an entity applies for its approved vendor or
7671	7671	26 designee status between delivery years, the Agency
7672	7672
7673	7673
7674	7674
7675	7675
7676	7676
7677	7677	HB3779 - 213 - LRB104 11172 AAS 21254 b
7678	7678
7679	7679
7680	7680	HB3779- 214 -LRB104 11172 AAS 21254 b HB3779 - 214 - LRB104 11172 AAS 21254 b
7681	7681	HB3779 - 214 - LRB104 11172 AAS 21254 b
7682	7682	1 shall require a compliance plan at the time of
7683	7683	2 application.
7684	7684	3 (B) Halfway through each delivery year, the Agency
7685	7685	4 shall require each entity participating in a
7686	7686	5 procurement program to confirm that it will achieve
7687	7687	6 compliance in that delivery year, when applicable. The
7688	7688	7 Agency may offer corrective action plans to entities
7689	7689	8 that are not on track to achieve compliance.
7690	7690	9 (C) At the end of each delivery year, each entity
7691	7691	10 participating and completing work in that delivery
7692	7692	11 year in a procurement program of subsection (c) shall
7693	7693	12 submit a report to the Agency that demonstrates how it
7694	7694	13 achieved compliance with the minimum equity standards
7695	7695	14 percentage for that delivery year.
7696	7696	15 (D) The Agency shall prohibit participation in
7697	7697	16 procurement programs by an approved vendor or
7698	7698	17 designee, as applicable, or entities with which an
7699	7699	18 approved vendor or designee, as applicable, shares a
7700	7700	19 common parent company if an approved vendor or
7701	7701	20 designee, as applicable, failed to meet the minimum
7702	7702	21 equity standards for the prior delivery year. Waivers
7703	7703	22 approved for lack of equity eligible persons or equity
7704	7704	23 eligible contractors in a geographic area of a project
7705	7705	24 shall not count against the approved vendor or
7706	7706	25 designee. The Agency shall offer a corrective action
7707	7707	26 plan for any such entities to assist them in obtaining
7708	7708
7709	7709
7710	7710
7711	7711
7712	7712
7713	7713	HB3779 - 214 - LRB104 11172 AAS 21254 b
7714	7714
7715	7715
7716	7716	HB3779- 215 -LRB104 11172 AAS 21254 b HB3779 - 215 - LRB104 11172 AAS 21254 b
7717	7717	HB3779 - 215 - LRB104 11172 AAS 21254 b
7718	7718	1 compliance and shall allow continued access to
7719	7719	2 procurement programs upon an approved vendor or
7720	7720	3 designee demonstrating compliance.
7721	7721	4 (E) The Agency shall pursue efficiencies achieved
7722	7722	5 by combining with other approved vendor or designee
7723	7723	6 reporting.
7724	7724	7 (2) Equity accountability system within the Adjustable
7725	7725	8 Block program. The equity category described in item (vi)
7726	7726	9 of subparagraph (K) of subsection (c) is only available to
7727	7727	10 applicants that are equity eligible contractors.
7728	7728	11 (3) Equity accountability system within competitive
7729	7729	12 procurements. Through its long-term renewable resources
7730	7730	13 procurement plan, the Agency shall develop requirements
7731	7731	14 for ensuring that competitive procurement processes,
7732	7732	15 including utility-scale solar, utility-scale wind, and
7733	7733	16 brownfield site photovoltaic projects, advance the equity
7734	7734	17 goals of this subsection (c-10). Subject to Commission
7735	7735	18 approval, the Agency shall develop bid application
7736	7736	19 requirements and a bid evaluation methodology for ensuring
7737	7737	20 that utilization of equity eligible contractors, whether
7738	7738	21 as bidders or as participants on project development, is
7739	7739	22 optimized, including requiring that winning or successful
7740	7740	23 applicants for utility-scale projects are or will partner
7741	7741	24 with equity eligible contractors and giving preference to
7742	7742	25 bids through which a higher portion of contract value
7743	7743	26 flows to equity eligible contractors. To the extent
7744	7744
7745	7745
7746	7746
7747	7747
7748	7748
7749	7749	HB3779 - 215 - LRB104 11172 AAS 21254 b
7750	7750
7751	7751
7752	7752	HB3779- 216 -LRB104 11172 AAS 21254 b HB3779 - 216 - LRB104 11172 AAS 21254 b
7753	7753	HB3779 - 216 - LRB104 11172 AAS 21254 b
7754	7754	1 practicable, entities participating in competitive
7755	7755	2 procurements shall also be required to meet all the equity
7756	7756	3 accountability requirements for approved vendors and their
7757	7757	4 designees under this subsection (c-10). In developing
7758	7758	5 these requirements, the Agency shall also consider whether
7759	7759	6 equity goals can be further advanced through additional
7760	7760	7 measures.
7761	7761	8 (4) In the first revision to the long-term renewable
7762	7762	9 energy resources procurement plan and each revision
7763	7763	10 thereafter, the Agency shall include the following:
7764	7764	11 (A) The current status and number of equity
7765	7765	12 eligible contractors listed in the Energy Workforce
7766	7766	13 Equity Database designed in subsection (c-25),
7767	7767	14 including the number of equity eligible contractors
7768	7768	15 with current certifications as issued by the Agency.
7769	7769	16 (B) A mechanism for measuring, tracking, and
7770	7770	17 reporting project workforce at the approved vendor or
7771	7771	18 designee level, as applicable, which shall include a
7772	7772	19 measurement methodology and records to be made
7773	7773	20 available for audit by the Agency or the Program
7774	7774	21 Administrator.
7775	7775	22 (C) A program for approved vendors, designees,
7776	7776	23 eligible persons, and equity eligible contractors to
7777	7777	24 receive trainings, guidance, and other support from
7778	7778	25 the Agency or its designee regarding the equity
7779	7779	26 category outlined in item (vi) of subparagraph (K) of
7780	7780
7781	7781
7782	7782
7783	7783
7784	7784
7785	7785	HB3779 - 216 - LRB104 11172 AAS 21254 b
7786	7786
7787	7787
7788	7788	HB3779- 217 -LRB104 11172 AAS 21254 b HB3779 - 217 - LRB104 11172 AAS 21254 b
7789	7789	HB3779 - 217 - LRB104 11172 AAS 21254 b
7790	7790	1 paragraph (1) of subsection (c) and in meeting the
7791	7791	2 minimum equity standards of this subsection (c-10).
7792	7792	3 (D) A process for certifying equity eligible
7793	7793	4 contractors and equity eligible persons. The
7794	7794	5 certification process shall coordinate with the Energy
7795	7795	6 Workforce Equity Database set forth in subsection
7796	7796	7 (c-25).
7797	7797	8 (E) An application for waiver of the minimum
7798	7798	9 equity standards of this subsection, which the Agency
7799	7799	10 shall have the discretion to grant in rare
7800	7800	11 circumstances. The Agency may grant such a waiver
7801	7801	12 where the applicant provides evidence of significant
7802	7802	13 efforts toward meeting the minimum equity commitment,
7803	7803	14 including: use of the Energy Workforce Equity
7804	7804	15 Database; efforts to hire or contract with entities
7805	7805	16 that hire eligible persons; and efforts to establish
7806	7806	17 contracting relationships with eligible contractors.
7807	7807	18 The Agency shall support applicants in understanding
7808	7808	19 the Energy Workforce Equity Database and other
7809	7809	20 resources for pursuing compliance of the minimum
7810	7810	21 equity standards. Waivers shall be project-specific,
7811	7811	22 unless the Agency deems it necessary to grant a waiver
7812	7812	23 across a portfolio of projects, and in effect for no
7813	7813	24 longer than one year. Any waiver extension or
7814	7814	25 subsequent waiver request from an applicant shall be
7815	7815	26 subject to the requirements of this Section and shall
7816	7816
7817	7817
7818	7818
7819	7819
7820	7820
7821	7821	HB3779 - 217 - LRB104 11172 AAS 21254 b
7822	7822
7823	7823
7824	7824	HB3779- 218 -LRB104 11172 AAS 21254 b HB3779 - 218 - LRB104 11172 AAS 21254 b
7825	7825	HB3779 - 218 - LRB104 11172 AAS 21254 b
7826	7826	1 specify efforts made to reach compliance. When
7827	7827	2 considering whether to grant a waiver, and to what
7828	7828	3 extent, the Agency shall consider the degree to which
7829	7829	4 similarly situated applicants have been able to meet
7830	7830	5 these minimum equity commitments. For repeated waiver
7831	7831	6 requests for specific lack of eligible persons or
7832	7832	7 eligible contractors available, the Agency shall make
7833	7833	8 recommendations to target recruitment to add such
7834	7834	9 eligible persons or eligible contractors to the
7835	7835	10 database.
7836	7836	11 (5) The Agency shall collect information about work on
7837	7837	12 projects or portfolios of projects subject to these
7838	7838	13 minimum equity standards to ensure compliance with this
7839	7839	14 subsection (c-10). Reporting in furtherance of this
7840	7840	15 requirement may be combined with other annual reporting
7841	7841	16 requirements. Such reporting shall include proof of
7842	7842	17 certification of each equity eligible contractor or equity
7843	7843	18 eligible person during the applicable time period.
7844	7844	19 (6) The Agency shall keep confidential all information
7845	7845	20 and communication that provides private or personal
7846	7846	21 information.
7847	7847	22 (7) Modifications to the equity accountability system.
7848	7848	23 As part of the update of the long-term renewable resources
7849	7849	24 procurement plan to be initiated in 2023, or sooner if the
7850	7850	25 Agency deems necessary, the Agency shall determine the
7851	7851	26 extent to which the equity accountability system described
7852	7852
7853	7853
7854	7854
7855	7855
7856	7856
7857	7857	HB3779 - 218 - LRB104 11172 AAS 21254 b
7858	7858
7859	7859
7860	7860	HB3779- 219 -LRB104 11172 AAS 21254 b HB3779 - 219 - LRB104 11172 AAS 21254 b
7861	7861	HB3779 - 219 - LRB104 11172 AAS 21254 b
7862	7862	1 in this subsection (c-10) has advanced the goals of this
7863	7863	2 amendatory Act of the 102nd General Assembly, including
7864	7864	3 through the inclusion of equity eligible persons and
7865	7865	4 equity eligible contractors in renewable energy credit
7866	7866	5 projects. If the Agency finds that the equity
7867	7867	6 accountability system has failed to meet those goals to
7868	7868	7 its fullest potential, the Agency may revise the following
7869	7869	8 criteria for future Agency procurements: (A) the
7870	7870	9 percentage of project workforce, or other appropriate
7871	7871	10 workforce measure, certified as equity eligible persons or
7872	7872	11 equity eligible contractors; (B) definitions for equity
7873	7873	12 investment eligible persons and equity investment eligible
7874	7874	13 community; and (C) such other modifications necessary to
7875	7875	14 advance the goals of this amendatory Act of the 102nd
7876	7876	15 General Assembly effectively. Such revised criteria may
7877	7877	16 also establish distinct equity accountability systems for
7878	7878	17 different types of procurements or different regions of
7879	7879	18 the State if the Agency finds that doing so will further
7880	7880	19 the purposes of such programs. Revisions shall be
7881	7881	20 developed with stakeholder input, including from equity
7882	7882	21 eligible persons, equity eligible contractors, and
7883	7883	22 community-based organizations that work with such persons
7884	7884	23 and contractors.
7885	7885	24 (c-15) Racial discrimination elimination powers and
7886	7886	25 process.
7887	7887	26 (1) Purpose. It is the purpose of this subsection to
7888	7888
7889	7889
7890	7890
7891	7891
7892	7892
7893	7893	HB3779 - 219 - LRB104 11172 AAS 21254 b
7894	7894
7895	7895
7896	7896	HB3779- 220 -LRB104 11172 AAS 21254 b HB3779 - 220 - LRB104 11172 AAS 21254 b
7897	7897	HB3779 - 220 - LRB104 11172 AAS 21254 b
7898	7898	1 empower the Agency and other State actors to remedy racial
7899	7899	2 discrimination in Illinois' clean energy economy as
7900	7900	3 effectively and expediently as possible, including through
7901	7901	4 the use of race-conscious remedies, such as race-conscious
7902	7902	5 contracting and hiring goals, as consistent with State and
7903	7903	6 federal law.
7904	7904	7 (2) Racial disparity and discrimination review
7905	7905	8 process.
7906	7906	9 (A) Within one year after awarding contracts using
7907	7907	10 the equity actions processes established in this
7908	7908	11 Section, the Agency shall publish a report evaluating
7909	7909	12 the effectiveness of the equity actions point criteria
7910	7910	13 of this Section in increasing participation of equity
7911	7911	14 eligible persons and equity eligible contractors. The
7912	7912	15 report shall disaggregate participating workers and
7913	7913	16 contractors by race and ethnicity. The report shall be
7914	7914	17 forwarded to the Governor, the General Assembly, and
7915	7915	18 the Illinois Commerce Commission and be made available
7916	7916	19 to the public.
7917	7917	20 (B) As soon as is practicable thereafter, the
7918	7918	21 Agency, in consultation with the Department of
7919	7919	22 Commerce and Economic Opportunity, Department of
7920	7920	23 Labor, and other agencies that may be relevant, shall
7921	7921	24 commission and publish a disparity and availability
7922	7922	25 study that measures the presence and impact of
7923	7923	26 discrimination on minority businesses and workers in
7924	7924
7925	7925
7926	7926
7927	7927
7928	7928
7929	7929	HB3779 - 220 - LRB104 11172 AAS 21254 b
7930	7930
7931	7931
7932	7932	HB3779- 221 -LRB104 11172 AAS 21254 b HB3779 - 221 - LRB104 11172 AAS 21254 b
7933	7933	HB3779 - 221 - LRB104 11172 AAS 21254 b
7934	7934	1 Illinois' clean energy economy. The Agency may hire
7935	7935	2 consultants and experts to conduct the disparity and
7936	7936	3 availability study, with the retention of those
7937	7937	4 consultants and experts exempt from the requirements
7938	7938	5 of Section 20-10 of the Illinois Procurement Code. The
7939	7939	6 Illinois Power Agency shall forward a copy of its
7940	7940	7 findings and recommendations to the Governor, the
7941	7941	8 General Assembly, and the Illinois Commerce
7942	7942	9 Commission. If the disparity and availability study
7943	7943	10 establishes a strong basis in evidence that there is
7944	7944	11 discrimination in Illinois' clean energy economy, the
7945	7945	12 Agency, Department of Commerce and Economic
7946	7946	13 Opportunity, Department of Labor, Department of
7947	7947	14 Corrections, and other appropriate agencies shall take
7948	7948	15 appropriate remedial actions, including race-conscious
7949	7949	16 remedial actions as consistent with State and federal
7950	7950	17 law, to effectively remedy this discrimination. Such
7951	7951	18 remedies may include modification of the equity
7952	7952	19 accountability system as described in subsection
7953	7953	20 (c-10).
7954	7954	21 (c-20) Program data collection.
7955	7955	22 (1) Purpose. Data collection, data analysis, and
7956	7956	23 reporting are critical to ensure that the benefits of the
7957	7957	24 clean energy economy provided to Illinois residents and
7958	7958	25 businesses are equitably distributed across the State. The
7959	7959	26 Agency shall collect data from program applicants in order
7960	7960
7961	7961
7962	7962
7963	7963
7964	7964
7965	7965	HB3779 - 221 - LRB104 11172 AAS 21254 b
7966	7966
7967	7967
7968	7968	HB3779- 222 -LRB104 11172 AAS 21254 b HB3779 - 222 - LRB104 11172 AAS 21254 b
7969	7969	HB3779 - 222 - LRB104 11172 AAS 21254 b
7970	7970	1 to track and improve equitable distribution of benefits
7971	7971	2 across Illinois communities for all procurements the
7972	7972	3 Agency conducts. The Agency shall use this data to, among
7973	7973	4 other things, measure any potential impact of racial
7974	7974	5 discrimination on the distribution of benefits and provide
7975	7975	6 information necessary to correct any discrimination
7976	7976	7 through methods consistent with State and federal law.
7977	7977	8 (2) Agency collection of program data. The Agency
7978	7978	9 shall collect demographic and geographic data for each
7979	7979	10 entity awarded contracts under any Agency-administered
7980	7980	11 program.
7981	7981	12 (3) Required information to be collected. The Agency
7982	7982	13 shall collect the following information from applicants
7983	7983	14 and program participants where applicable:
7984	7984	15 (A) demographic information, including racial or
7985	7985	16 ethnic identity for real persons employed, contracted,
7986	7986	17 or subcontracted through the program and owners of
7987	7987	18 businesses or entities that apply to receive renewable
7988	7988	19 energy credits from the Agency;
7989	7989	20 (B) geographic location of the residency of real
7990	7990	21 persons employed, contracted, or subcontracted through
7991	7991	22 the program and geographic location of the
7992	7992	23 headquarters of the business or entity that applies to
7993	7993	24 receive renewable energy credits from the Agency; and
7994	7994	25 (C) any other information the Agency determines is
7995	7995	26 necessary for the purpose of achieving the purpose of
7996	7996
7997	7997
7998	7998
7999	7999
8000	8000
8001	8001	HB3779 - 222 - LRB104 11172 AAS 21254 b
8002	8002
8003	8003
8004	8004	HB3779- 223 -LRB104 11172 AAS 21254 b HB3779 - 223 - LRB104 11172 AAS 21254 b
8005	8005	HB3779 - 223 - LRB104 11172 AAS 21254 b
8006	8006	1 this subsection.
8007	8007	2 (4) Publication of collected information. The Agency
8008	8008	3 shall publish, at least annually, information on the
8009	8009	4 demographics of program participants on an aggregate
8010	8010	5 basis.
8011	8011	6 (5) Nothing in this subsection shall be interpreted to
8012	8012	7 limit the authority of the Agency, or other agency or
8013	8013	8 department of the State, to require or collect demographic
8014	8014	9 information from applicants of other State programs.
8015	8015	10 (c-25) Energy Workforce Equity Database.
8016	8016	11 (1) The Agency, in consultation with the Department of
8017	8017	12 Commerce and Economic Opportunity, shall create an Energy
8018	8018	13 Workforce Equity Database, and may contract with a third
8019	8019	14 party to do so ("database program administrator"). If the
8020	8020	15 Department decides to contract with a third party, that
8021	8021	16 third party shall be exempt from the requirements of
8022	8022	17 Section 20-10 of the Illinois Procurement Code. The Energy
8023	8023	18 Workforce Equity Database shall be a searchable database
8024	8024	19 of suppliers, vendors, and subcontractors for clean energy
8025	8025	20 industries that is:
8026	8026	21 (A) publicly accessible;
8027	8027	22 (B) easy for people to find and use;
8028	8028	23 (C) organized by company specialty or field;
8029	8029	24 (D) region-specific; and
8030	8030	25 (E) populated with information including, but not
8031	8031	26 limited to, contacts for suppliers, vendors, or
8032	8032
8033	8033
8034	8034
8035	8035
8036	8036
8037	8037	HB3779 - 223 - LRB104 11172 AAS 21254 b
8038	8038
8039	8039
8040	8040	HB3779- 224 -LRB104 11172 AAS 21254 b HB3779 - 224 - LRB104 11172 AAS 21254 b
8041	8041	HB3779 - 224 - LRB104 11172 AAS 21254 b
8042	8042	1 subcontractors who are minority and women-owned
8043	8043	2 business enterprise certified or who participate or
8044	8044	3 have participated in any of the programs described in
8045	8045	4 this Act.
8046	8046	5 (2) The Agency shall create an easily accessible,
8047	8047	6 public facing online tool using the database information
8048	8048	7 that includes, at a minimum, the following:
8049	8049	8 (A) a map of environmental justice and equity
8050	8050	9 investment eligible communities;
8051	8051	10 (B) job postings and recruiting opportunities;
8052	8052	11 (C) a means by which recruiting clean energy
8053	8053	12 companies can find and interact with current or former
8054	8054	13 participants of clean energy workforce training
8055	8055	14 programs;
8056	8056	15 (D) information on workforce training service
8057	8057	16 providers and training opportunities available to
8058	8058	17 prospective workers;
8059	8059	18 (E) renewable energy company diversity reporting;
8060	8060	19 (F) a list of equity eligible contractors with
8061	8061	20 their contact information, types of work performed,
8062	8062	21 and locations worked in;
8063	8063	22 (G) reporting on outcomes of the programs
8064	8064	23 described in the workforce programs of the Energy
8065	8065	24 Transition Act, including information such as, but not
8066	8066	25 limited to, retention rate, graduation rate, and
8067	8067	26 placement rates of trainees; and
8068	8068
8069	8069
8070	8070
8071	8071
8072	8072
8073	8073	HB3779 - 224 - LRB104 11172 AAS 21254 b
8074	8074
8075	8075
8076	8076	HB3779- 225 -LRB104 11172 AAS 21254 b HB3779 - 225 - LRB104 11172 AAS 21254 b
8077	8077	HB3779 - 225 - LRB104 11172 AAS 21254 b
8078	8078	1 (H) information about the Jobs and Environmental
8079	8079	2 Justice Grant Program, the Clean Energy Jobs and
8080	8080	3 Justice Fund, and other sources of capital.
8081	8081	4 (3) The Agency shall ensure the database is regularly
8082	8082	5 updated to ensure information is current and shall
8083	8083	6 coordinate with the Department of Commerce and Economic
8084	8084	7 Opportunity to ensure that it includes information on
8085	8085	8 individuals and entities that are or have participated in
8086	8086	9 the Clean Jobs Workforce Network Program, Clean Energy
8087	8087	10 Contractor Incubator Program, Returning Residents Clean
8088	8088	11 Jobs Training Program, or Clean Energy Primes Contractor
8089	8089	12 Accelerator Program.
8090	8090	13 (c-30) Enforcement of minimum equity standards. All
8091	8091	14 entities seeking renewable energy credits must submit an
8092	8092	15 annual report to demonstrate compliance with each of the
8093	8093	16 equity commitments required under subsection (c-10). If the
8094	8094	17 Agency concludes the entity has not met or maintained its
8095	8095	18 minimum equity standards required under the applicable
8096	8096	19 subparagraphs under subsection (c-10), the Agency shall deny
8097	8097	20 the entity's ability to participate in procurement programs in
8098	8098	21 subsection (c), including by withholding approved vendor or
8099	8099	22 designee status. The Agency may require the entity to enter
8100	8100	23 into a corrective action plan. An entity that is not
8101	8101	24 recertified for failing to meet required equity actions in
8102	8102	25 subparagraph (c-10) may reapply once they have a corrective
8103	8103	26 action plan and achieve compliance with the minimum equity
8104	8104
8105	8105
8106	8106
8107	8107
8108	8108
8109	8109	HB3779 - 225 - LRB104 11172 AAS 21254 b
8110	8110
8111	8111
8112	8112	HB3779- 226 -LRB104 11172 AAS 21254 b HB3779 - 226 - LRB104 11172 AAS 21254 b
8113	8113	HB3779 - 226 - LRB104 11172 AAS 21254 b
8114	8114	1 standards.
8115	8115	2 (d) Clean coal portfolio standard.
8116	8116	3 (1) The procurement plans shall include electricity
8117	8117	4 generated using clean coal. Each utility shall enter into
8118	8118	5 one or more sourcing agreements with the initial clean
8119	8119	6 coal facility, as provided in paragraph (3) of this
8120	8120	7 subsection (d), covering electricity generated by the
8121	8121	8 initial clean coal facility representing at least 5% of
8122	8122	9 each utility's total supply to serve the load of eligible
8123	8123	10 retail customers in 2015 and each year thereafter, as
8124	8124	11 described in paragraph (3) of this subsection (d), subject
8125	8125	12 to the limits specified in paragraph (2) of this
8126	8126	13 subsection (d). It is the goal of the State that by January
8127	8127	14 1, 2025, 25% of the electricity used in the State shall be
8128	8128	15 generated by cost-effective clean coal facilities. For
8129	8129	16 purposes of this subsection (d), "cost-effective" means
8130	8130	17 that the expenditures pursuant to such sourcing agreements
8131	8131	18 do not cause the limit stated in paragraph (2) of this
8132	8132	19 subsection (d) to be exceeded and do not exceed cost-based
8133	8133	20 benchmarks, which shall be developed to assess all
8134	8134	21 expenditures pursuant to such sourcing agreements covering
8135	8135	22 electricity generated by clean coal facilities, other than
8136	8136	23 the initial clean coal facility, by the procurement
8137	8137	24 administrator, in consultation with the Commission staff,
8138	8138	25 Agency staff, and the procurement monitor and shall be
8139	8139	26 subject to Commission review and approval.
8140	8140
8141	8141
8142	8142
8143	8143
8144	8144
8145	8145	HB3779 - 226 - LRB104 11172 AAS 21254 b
8146	8146
8147	8147
8148	8148	HB3779- 227 -LRB104 11172 AAS 21254 b HB3779 - 227 - LRB104 11172 AAS 21254 b
8149	8149	HB3779 - 227 - LRB104 11172 AAS 21254 b
8150	8150	1 A utility party to a sourcing agreement shall
8151	8151	2 immediately retire any emission credits that it receives
8152	8152	3 in connection with the electricity covered by such
8153	8153	4 agreement.
8154	8154	5 Utilities shall maintain adequate records documenting
8155	8155	6 the purchases under the sourcing agreement to comply with
8156	8156	7 this subsection (d) and shall file an accounting with the
8157	8157	8 load forecast that must be filed with the Agency by July 15
8158	8158	9 of each year, in accordance with subsection (d) of Section
8159	8159	10 16-111.5 of the Public Utilities Act.
8160	8160	11 A utility shall be deemed to have complied with the
8161	8161	12 clean coal portfolio standard specified in this subsection
8162	8162	13 (d) if the utility enters into a sourcing agreement as
8163	8163	14 required by this subsection (d).
8164	8164	15 (2) For purposes of this subsection (d), the required
8165	8165	16 execution of sourcing agreements with the initial clean
8166	8166	17 coal facility for a particular year shall be measured as a
8167	8167	18 percentage of the actual amount of electricity
8168	8168	19 (megawatt-hours) supplied by the electric utility to
8169	8169	20 eligible retail customers in the planning year ending
8170	8170	21 immediately prior to the agreement's execution. For
8171	8171	22 purposes of this subsection (d), the amount paid per
8172	8172	23 kilowatthour means the total amount paid for electric
8173	8173	24 service expressed on a per kilowatthour basis. For
8174	8174	25 purposes of this subsection (d), the total amount paid for
8175	8175	26 electric service includes without limitation amounts paid
8176	8176
8177	8177
8178	8178
8179	8179
8180	8180
8181	8181	HB3779 - 227 - LRB104 11172 AAS 21254 b
8182	8182
8183	8183
8184	8184	HB3779- 228 -LRB104 11172 AAS 21254 b HB3779 - 228 - LRB104 11172 AAS 21254 b
8185	8185	HB3779 - 228 - LRB104 11172 AAS 21254 b
8186	8186	1 for supply, transmission, distribution, surcharges and
8187	8187	2 add-on taxes.
8188	8188	3 Notwithstanding the requirements of this subsection
8189	8189	4 (d), the total amount paid under sourcing agreements with
8190	8190	5 clean coal facilities pursuant to the procurement plan for
8191	8191	6 any given year shall be reduced by an amount necessary to
8192	8192	7 limit the annual estimated average net increase due to the
8193	8193	8 costs of these resources included in the amounts paid by
8194	8194	9 eligible retail customers in connection with electric
8195	8195	10 service to:
8196	8196	11 (A) in 2010, no more than 0.5% of the amount paid
8197	8197	12 per kilowatthour by those customers during the year
8198	8198	13 ending May 31, 2009;
8199	8199	14 (B) in 2011, the greater of an additional 0.5% of
8200	8200	15 the amount paid per kilowatthour by those customers
8201	8201	16 during the year ending May 31, 2010 or 1% of the amount
8202	8202	17 paid per kilowatthour by those customers during the
8203	8203	18 year ending May 31, 2009;
8204	8204	19 (C) in 2012, the greater of an additional 0.5% of
8205	8205	20 the amount paid per kilowatthour by those customers
8206	8206	21 during the year ending May 31, 2011 or 1.5% of the
8207	8207	22 amount paid per kilowatthour by those customers during
8208	8208	23 the year ending May 31, 2009;
8209	8209	24 (D) in 2013, the greater of an additional 0.5% of
8210	8210	25 the amount paid per kilowatthour by those customers
8211	8211	26 during the year ending May 31, 2012 or 2% of the amount
8212	8212
8213	8213
8214	8214
8215	8215
8216	8216
8217	8217	HB3779 - 228 - LRB104 11172 AAS 21254 b
8218	8218
8219	8219
8220	8220	HB3779- 229 -LRB104 11172 AAS 21254 b HB3779 - 229 - LRB104 11172 AAS 21254 b
8221	8221	HB3779 - 229 - LRB104 11172 AAS 21254 b
8222	8222	1 paid per kilowatthour by those customers during the
8223	8223	2 year ending May 31, 2009; and
8224	8224	3 (E) thereafter, the total amount paid under
8225	8225	4 sourcing agreements with clean coal facilities
8226	8226	5 pursuant to the procurement plan for any single year
8227	8227	6 shall be reduced by an amount necessary to limit the
8228	8228	7 estimated average net increase due to the cost of
8229	8229	8 these resources included in the amounts paid by
8230	8230	9 eligible retail customers in connection with electric
8231	8231	10 service to no more than the greater of (i) 2.015% of
8232	8232	11 the amount paid per kilowatthour by those customers
8233	8233	12 during the year ending May 31, 2009 or (ii) the
8234	8234	13 incremental amount per kilowatthour paid for these
8235	8235	14 resources in 2013. These requirements may be altered
8236	8236	15 only as provided by statute.
8237	8237	16 No later than June 30, 2015, the Commission shall
8238	8238	17 review the limitation on the total amount paid under
8239	8239	18 sourcing agreements, if any, with clean coal facilities
8240	8240	19 pursuant to this subsection (d) and report to the General
8241	8241	20 Assembly its findings as to whether that limitation unduly
8242	8242	21 constrains the amount of electricity generated by
8243	8243	22 cost-effective clean coal facilities that is covered by
8244	8244	23 sourcing agreements.
8245	8245	24 (3) Initial clean coal facility. In order to promote
8246	8246	25 development of clean coal facilities in Illinois, each
8247	8247	26 electric utility subject to this Section shall execute a
8248	8248
8249	8249
8250	8250
8251	8251
8252	8252
8253	8253	HB3779 - 229 - LRB104 11172 AAS 21254 b
8254	8254
8255	8255
8256	8256	HB3779- 230 -LRB104 11172 AAS 21254 b HB3779 - 230 - LRB104 11172 AAS 21254 b
8257	8257	HB3779 - 230 - LRB104 11172 AAS 21254 b
8258	8258	1 sourcing agreement to source electricity from a proposed
8259	8259	2 clean coal facility in Illinois (the "initial clean coal
8260	8260	3 facility") that will have a nameplate capacity of at least
8261	8261	4 500 MW when commercial operation commences, that has a
8262	8262	5 final Clean Air Act permit on June 1, 2009 (the effective
8263	8263	6 date of Public Act 95-1027), and that will meet the
8264	8264	7 definition of clean coal facility in Section 1-10 of this
8265	8265	8 Act when commercial operation commences. The sourcing
8266	8266	9 agreements with this initial clean coal facility shall be
8267	8267	10 subject to both approval of the initial clean coal
8268	8268	11 facility by the General Assembly and satisfaction of the
8269	8269	12 requirements of paragraph (4) of this subsection (d) and
8270	8270	13 shall be executed within 90 days after any such approval
8271	8271	14 by the General Assembly. The Agency and the Commission
8272	8272	15 shall have authority to inspect all books and records
8273	8273	16 associated with the initial clean coal facility during the
8274	8274	17 term of such a sourcing agreement. A utility's sourcing
8275	8275	18 agreement for electricity produced by the initial clean
8276	8276	19 coal facility shall include:
8277	8277	20 (A) a formula contractual price (the "contract
8278	8278	21 price") approved pursuant to paragraph (4) of this
8279	8279	22 subsection (d), which shall:
8280	8280	23 (i) be determined using a cost of service
8281	8281	24 methodology employing either a level or deferred
8282	8282	25 capital recovery component, based on a capital
8283	8283	26 structure consisting of 45% equity and 55% debt,
8284	8284
8285	8285
8286	8286
8287	8287
8288	8288
8289	8289	HB3779 - 230 - LRB104 11172 AAS 21254 b
8290	8290
8291	8291
8292	8292	HB3779- 231 -LRB104 11172 AAS 21254 b HB3779 - 231 - LRB104 11172 AAS 21254 b
8293	8293	HB3779 - 231 - LRB104 11172 AAS 21254 b
8294	8294	1 and a return on equity as may be approved by the
8295	8295	2 Federal Energy Regulatory Commission, which in any
8296	8296	3 case may not exceed the lower of 11.5% or the rate
8297	8297	4 of return approved by the General Assembly
8298	8298	5 pursuant to paragraph (4) of this subsection (d);
8299	8299	6 and
8300	8300	7 (ii) provide that all miscellaneous net
8301	8301	8 revenue, including but not limited to net revenue
8302	8302	9 from the sale of emission allowances, if any,
8303	8303	10 substitute natural gas, if any, grants or other
8304	8304	11 support provided by the State of Illinois or the
8305	8305	12 United States Government, firm transmission
8306	8306	13 rights, if any, by-products produced by the
8307	8307	14 facility, energy or capacity derived from the
8308	8308	15 facility and not covered by a sourcing agreement
8309	8309	16 pursuant to paragraph (3) of this subsection (d)
8310	8310	17 or item (5) of subsection (d) of Section 16-115 of
8311	8311	18 the Public Utilities Act, whether generated from
8312	8312	19 the synthesis gas derived from coal, from SNG, or
8313	8313	20 from natural gas, shall be credited against the
8314	8314	21 revenue requirement for this initial clean coal
8315	8315	22 facility;
8316	8316	23 (B) power purchase provisions, which shall:
8317	8317	24 (i) provide that the utility party to such
8318	8318	25 sourcing agreement shall pay the contract price
8319	8319	26 for electricity delivered under such sourcing
8320	8320
8321	8321
8322	8322
8323	8323
8324	8324
8325	8325	HB3779 - 231 - LRB104 11172 AAS 21254 b
8326	8326
8327	8327
8328	8328	HB3779- 232 -LRB104 11172 AAS 21254 b HB3779 - 232 - LRB104 11172 AAS 21254 b
8329	8329	HB3779 - 232 - LRB104 11172 AAS 21254 b
8330	8330	1 agreement;
8331	8331	2 (ii) require delivery of electricity to the
8332	8332	3 regional transmission organization market of the
8333	8333	4 utility that is party to such sourcing agreement;
8334	8334	5 (iii) require the utility party to such
8335	8335	6 sourcing agreement to buy from the initial clean
8336	8336	7 coal facility in each hour an amount of energy
8337	8337	8 equal to all clean coal energy made available from
8338	8338	9 the initial clean coal facility during such hour
8339	8339	10 times a fraction, the numerator of which is such
8340	8340	11 utility's retail market sales of electricity
8341	8341	12 (expressed in kilowatthours sold) in the State
8342	8342	13 during the prior calendar month and the
8343	8343	14 denominator of which is the total retail market
8344	8344	15 sales of electricity (expressed in kilowatthours
8345	8345	16 sold) in the State by utilities during such prior
8346	8346	17 month and the sales of electricity (expressed in
8347	8347	18 kilowatthours sold) in the State by alternative
8348	8348	19 retail electric suppliers during such prior month
8349	8349	20 that are subject to the requirements of this
8350	8350	21 subsection (d) and paragraph (5) of subsection (d)
8351	8351	22 of Section 16-115 of the Public Utilities Act,
8352	8352	23 provided that the amount purchased by the utility
8353	8353	24 in any year will be limited by paragraph (2) of
8354	8354	25 this subsection (d); and
8355	8355	26 (iv) be considered pre-existing contracts in
8356	8356
8357	8357
8358	8358
8359	8359
8360	8360
8361	8361	HB3779 - 232 - LRB104 11172 AAS 21254 b
8362	8362
8363	8363
8364	8364	HB3779- 233 -LRB104 11172 AAS 21254 b HB3779 - 233 - LRB104 11172 AAS 21254 b
8365	8365	HB3779 - 233 - LRB104 11172 AAS 21254 b
8366	8366	1 such utility's procurement plans for eligible
8367	8367	2 retail customers;
8368	8368	3 (C) contract for differences provisions, which
8369	8369	4 shall:
8370	8370	5 (i) require the utility party to such sourcing
8371	8371	6 agreement to contract with the initial clean coal
8372	8372	7 facility in each hour with respect to an amount of
8373	8373	8 energy equal to all clean coal energy made
8374	8374	9 available from the initial clean coal facility
8375	8375	10 during such hour times a fraction, the numerator
8376	8376	11 of which is such utility's retail market sales of
8377	8377	12 electricity (expressed in kilowatthours sold) in
8378	8378	13 the utility's service territory in the State
8379	8379	14 during the prior calendar month and the
8380	8380	15 denominator of which is the total retail market
8381	8381	16 sales of electricity (expressed in kilowatthours
8382	8382	17 sold) in the State by utilities during such prior
8383	8383	18 month and the sales of electricity (expressed in
8384	8384	19 kilowatthours sold) in the State by alternative
8385	8385	20 retail electric suppliers during such prior month
8386	8386	21 that are subject to the requirements of this
8387	8387	22 subsection (d) and paragraph (5) of subsection (d)
8388	8388	23 of Section 16-115 of the Public Utilities Act,
8389	8389	24 provided that the amount paid by the utility in
8390	8390	25 any year will be limited by paragraph (2) of this
8391	8391	26 subsection (d);
8392	8392
8393	8393
8394	8394
8395	8395
8396	8396
8397	8397	HB3779 - 233 - LRB104 11172 AAS 21254 b
8398	8398
8399	8399
8400	8400	HB3779- 234 -LRB104 11172 AAS 21254 b HB3779 - 234 - LRB104 11172 AAS 21254 b
8401	8401	HB3779 - 234 - LRB104 11172 AAS 21254 b
8402	8402	1 (ii) provide that the utility's payment
8403	8403	2 obligation in respect of the quantity of
8404	8404	3 electricity determined pursuant to the preceding
8405	8405	4 clause (i) shall be limited to an amount equal to
8406	8406	5 (1) the difference between the contract price
8407	8407	6 determined pursuant to subparagraph (A) of
8408	8408	7 paragraph (3) of this subsection (d) and the
8409	8409	8 day-ahead price for electricity delivered to the
8410	8410	9 regional transmission organization market of the
8411	8411	10 utility that is party to such sourcing agreement
8412	8412	11 (or any successor delivery point at which such
8413	8413	12 utility's supply obligations are financially
8414	8414	13 settled on an hourly basis) (the "reference
8415	8415	14 price") on the day preceding the day on which the
8416	8416	15 electricity is delivered to the initial clean coal
8417	8417	16 facility busbar, multiplied by (2) the quantity of
8418	8418	17 electricity determined pursuant to the preceding
8419	8419	18 clause (i); and
8420	8420	19 (iii) not require the utility to take physical
8421	8421	20 delivery of the electricity produced by the
8422	8422	21 facility;
8423	8423	22 (D) general provisions, which shall:
8424	8424	23 (i) specify a term of no more than 30 years,
8425	8425	24 commencing on the commercial operation date of the
8426	8426	25 facility;
8427	8427	26 (ii) provide that utilities shall maintain
8428	8428
8429	8429
8430	8430
8431	8431
8432	8432
8433	8433	HB3779 - 234 - LRB104 11172 AAS 21254 b
8434	8434
8435	8435
8436	8436	HB3779- 235 -LRB104 11172 AAS 21254 b HB3779 - 235 - LRB104 11172 AAS 21254 b
8437	8437	HB3779 - 235 - LRB104 11172 AAS 21254 b
8438	8438	1 adequate records documenting purchases under the
8439	8439	2 sourcing agreements entered into to comply with
8440	8440	3 this subsection (d) and shall file an accounting
8441	8441	4 with the load forecast that must be filed with the
8442	8442	5 Agency by July 15 of each year, in accordance with
8443	8443	6 subsection (d) of Section 16-111.5 of the Public
8444	8444	7 Utilities Act;
8445	8445	8 (iii) provide that all costs associated with
8446	8446	9 the initial clean coal facility will be
8447	8447	10 periodically reported to the Federal Energy
8448	8448	11 Regulatory Commission and to purchasers in
8449	8449	12 accordance with applicable laws governing
8450	8450	13 cost-based wholesale power contracts;
8451	8451	14 (iv) permit the Illinois Power Agency to
8452	8452	15 assume ownership of the initial clean coal
8453	8453	16 facility, without monetary consideration and
8454	8454	17 otherwise on reasonable terms acceptable to the
8455	8455	18 Agency, if the Agency so requests no less than 3
8456	8456	19 years prior to the end of the stated contract
8457	8457	20 term;
8458	8458	21 (v) require the owner of the initial clean
8459	8459	22 coal facility to provide documentation to the
8460	8460	23 Commission each year, starting in the facility's
8461	8461	24 first year of commercial operation, accurately
8462	8462	25 reporting the quantity of carbon emissions from
8463	8463	26 the facility that have been captured and
8464	8464
8465	8465
8466	8466
8467	8467
8468	8468
8469	8469	HB3779 - 235 - LRB104 11172 AAS 21254 b
8470	8470
8471	8471
8472	8472	HB3779- 236 -LRB104 11172 AAS 21254 b HB3779 - 236 - LRB104 11172 AAS 21254 b
8473	8473	HB3779 - 236 - LRB104 11172 AAS 21254 b
8474	8474	1 sequestered and report any quantities of carbon
8475	8475	2 released from the site or sites at which carbon
8476	8476	3 emissions were sequestered in prior years, based
8477	8477	4 on continuous monitoring of such sites. If, in any
8478	8478	5 year after the first year of commercial operation,
8479	8479	6 the owner of the facility fails to demonstrate
8480	8480	7 that the initial clean coal facility captured and
8481	8481	8 sequestered at least 50% of the total carbon
8482	8482	9 emissions that the facility would otherwise emit
8483	8483	10 or that sequestration of emissions from prior
8484	8484	11 years has failed, resulting in the release of
8485	8485	12 carbon dioxide into the atmosphere, the owner of
8486	8486	13 the facility must offset excess emissions. Any
8487	8487	14 such carbon offsets must be permanent, additional,
8488	8488	15 verifiable, real, located within the State of
8489	8489	16 Illinois, and legally and practicably enforceable.
8490	8490	17 The cost of such offsets for the facility that are
8491	8491	18 not recoverable shall not exceed $15 million in
8492	8492	19 any given year. No costs of any such purchases of
8493	8493	20 carbon offsets may be recovered from a utility or
8494	8494	21 its customers. All carbon offsets purchased for
8495	8495	22 this purpose and any carbon emission credits
8496	8496	23 associated with sequestration of carbon from the
8497	8497	24 facility must be permanently retired. The initial
8498	8498	25 clean coal facility shall not forfeit its
8499	8499	26 designation as a clean coal facility if the
8500	8500
8501	8501
8502	8502
8503	8503
8504	8504
8505	8505	HB3779 - 236 - LRB104 11172 AAS 21254 b
8506	8506
8507	8507
8508	8508	HB3779- 237 -LRB104 11172 AAS 21254 b HB3779 - 237 - LRB104 11172 AAS 21254 b
8509	8509	HB3779 - 237 - LRB104 11172 AAS 21254 b
8510	8510	1 facility fails to fully comply with the applicable
8511	8511	2 carbon sequestration requirements in any given
8512	8512	3 year, provided the requisite offsets are
8513	8513	4 purchased. However, the Attorney General, on
8514	8514	5 behalf of the People of the State of Illinois, may
8515	8515	6 specifically enforce the facility's sequestration
8516	8516	7 requirement and the other terms of this contract
8517	8517	8 provision. Compliance with the sequestration
8518	8518	9 requirements and offset purchase requirements
8519	8519	10 specified in paragraph (3) of this subsection (d)
8520	8520	11 shall be reviewed annually by an independent
8521	8521	12 expert retained by the owner of the initial clean
8522	8522	13 coal facility, with the advance written approval
8523	8523	14 of the Attorney General. The Commission may, in
8524	8524	15 the course of the review specified in item (vii),
8525	8525	16 reduce the allowable return on equity for the
8526	8526	17 facility if the facility willfully fails to comply
8527	8527	18 with the carbon capture and sequestration
8528	8528	19 requirements set forth in this item (v);
8529	8529	20 (vi) include limits on, and accordingly
8530	8530	21 provide for modification of, the amount the
8531	8531	22 utility is required to source under the sourcing
8532	8532	23 agreement consistent with paragraph (2) of this
8533	8533	24 subsection (d);
8534	8534	25 (vii) require Commission review: (1) to
8535	8535	26 determine the justness, reasonableness, and
8536	8536
8537	8537
8538	8538
8539	8539
8540	8540
8541	8541	HB3779 - 237 - LRB104 11172 AAS 21254 b
8542	8542
8543	8543
8544	8544	HB3779- 238 -LRB104 11172 AAS 21254 b HB3779 - 238 - LRB104 11172 AAS 21254 b
8545	8545	HB3779 - 238 - LRB104 11172 AAS 21254 b
8546	8546	1 prudence of the inputs to the formula referenced
8547	8547	2 in subparagraphs (A)(i) through (A)(iii) of
8548	8548	3 paragraph (3) of this subsection (d), prior to an
8549	8549	4 adjustment in those inputs including, without
8550	8550	5 limitation, the capital structure and return on
8551	8551	6 equity, fuel costs, and other operations and
8552	8552	7 maintenance costs and (2) to approve the costs to
8553	8553	8 be passed through to customers under the sourcing
8554	8554	9 agreement by which the utility satisfies its
8555	8555	10 statutory obligations. Commission review shall
8556	8556	11 occur no less than every 3 years, regardless of
8557	8557	12 whether any adjustments have been proposed, and
8558	8558	13 shall be completed within 9 months;
8559	8559	14 (viii) limit the utility's obligation to such
8560	8560	15 amount as the utility is allowed to recover
8561	8561	16 through tariffs filed with the Commission,
8562	8562	17 provided that neither the clean coal facility nor
8563	8563	18 the utility waives any right to assert federal
8564	8564	19 pre-emption or any other argument in response to a
8565	8565	20 purported disallowance of recovery costs;
8566	8566	21 (ix) limit the utility's or alternative retail
8567	8567	22 electric supplier's obligation to incur any
8568	8568	23 liability until such time as the facility is in
8569	8569	24 commercial operation and generating power and
8570	8570	25 energy and such power and energy is being
8571	8571	26 delivered to the facility busbar;
8572	8572
8573	8573
8574	8574
8575	8575
8576	8576
8577	8577	HB3779 - 238 - LRB104 11172 AAS 21254 b
8578	8578
8579	8579
8580	8580	HB3779- 239 -LRB104 11172 AAS 21254 b HB3779 - 239 - LRB104 11172 AAS 21254 b
8581	8581	HB3779 - 239 - LRB104 11172 AAS 21254 b
8582	8582	1 (x) provide that the owner or owners of the
8583	8583	2 initial clean coal facility, which is the
8584	8584	3 counterparty to such sourcing agreement, shall
8585	8585	4 have the right from time to time to elect whether
8586	8586	5 the obligations of the utility party thereto shall
8587	8587	6 be governed by the power purchase provisions or
8588	8588	7 the contract for differences provisions;
8589	8589	8 (xi) append documentation showing that the
8590	8590	9 formula rate and contract, insofar as they relate
8591	8591	10 to the power purchase provisions, have been
8592	8592	11 approved by the Federal Energy Regulatory
8593	8593	12 Commission pursuant to Section 205 of the Federal
8594	8594	13 Power Act;
8595	8595	14 (xii) provide that any changes to the terms of
8596	8596	15 the contract, insofar as such changes relate to
8597	8597	16 the power purchase provisions, are subject to
8598	8598	17 review under the public interest standard applied
8599	8599	18 by the Federal Energy Regulatory Commission
8600	8600	19 pursuant to Sections 205 and 206 of the Federal
8601	8601	20 Power Act; and
8602	8602	21 (xiii) conform with customary lender
8603	8603	22 requirements in power purchase agreements used as
8604	8604	23 the basis for financing non-utility generators.
8605	8605	24 (4) Effective date of sourcing agreements with the
8606	8606	25 initial clean coal facility. Any proposed sourcing
8607	8607	26 agreement with the initial clean coal facility shall not
8608	8608
8609	8609
8610	8610
8611	8611
8612	8612
8613	8613	HB3779 - 239 - LRB104 11172 AAS 21254 b
8614	8614
8615	8615
8616	8616	HB3779- 240 -LRB104 11172 AAS 21254 b HB3779 - 240 - LRB104 11172 AAS 21254 b
8617	8617	HB3779 - 240 - LRB104 11172 AAS 21254 b
8618	8618	1 become effective unless the following reports are prepared
8619	8619	2 and submitted and authorizations and approvals obtained:
8620	8620	3 (i) Facility cost report. The owner of the initial
8621	8621	4 clean coal facility shall submit to the Commission,
8622	8622	5 the Agency, and the General Assembly a front-end
8623	8623	6 engineering and design study, a facility cost report,
8624	8624	7 method of financing (including but not limited to
8625	8625	8 structure and associated costs), and an operating and
8626	8626	9 maintenance cost quote for the facility (collectively
8627	8627	10 "facility cost report"), which shall be prepared in
8628	8628	11 accordance with the requirements of this paragraph (4)
8629	8629	12 of subsection (d) of this Section, and shall provide
8630	8630	13 the Commission and the Agency access to the work
8631	8631	14 papers, relied upon documents, and any other backup
8632	8632	15 documentation related to the facility cost report.
8633	8633	16 (ii) Commission report. Within 6 months following
8634	8634	17 receipt of the facility cost report, the Commission,
8635	8635	18 in consultation with the Agency, shall submit a report
8636	8636	19 to the General Assembly setting forth its analysis of
8637	8637	20 the facility cost report. Such report shall include,
8638	8638	21 but not be limited to, a comparison of the costs
8639	8639	22 associated with electricity generated by the initial
8640	8640	23 clean coal facility to the costs associated with
8641	8641	24 electricity generated by other types of generation
8642	8642	25 facilities, an analysis of the rate impacts on
8643	8643	26 residential and small business customers over the life
8644	8644
8645	8645
8646	8646
8647	8647
8648	8648
8649	8649	HB3779 - 240 - LRB104 11172 AAS 21254 b
8650	8650
8651	8651
8652	8652	HB3779- 241 -LRB104 11172 AAS 21254 b HB3779 - 241 - LRB104 11172 AAS 21254 b
8653	8653	HB3779 - 241 - LRB104 11172 AAS 21254 b
8654	8654	1 of the sourcing agreements, and an analysis of the
8655	8655	2 likelihood that the initial clean coal facility will
8656	8656	3 commence commercial operation by and be delivering
8657	8657	4 power to the facility's busbar by 2016. To assist in
8658	8658	5 the preparation of its report, the Commission, in
8659	8659	6 consultation with the Agency, may hire one or more
8660	8660	7 experts or consultants, the costs of which shall be
8661	8661	8 paid for by the owner of the initial clean coal
8662	8662	9 facility. The Commission and Agency may begin the
8663	8663	10 process of selecting such experts or consultants prior
8664	8664	11 to receipt of the facility cost report.
8665	8665	12 (iii) General Assembly approval. The proposed
8666	8666	13 sourcing agreements shall not take effect unless,
8667	8667	14 based on the facility cost report and the Commission's
8668	8668	15 report, the General Assembly enacts authorizing
8669	8669	16 legislation approving (A) the projected price, stated
8670	8670	17 in cents per kilowatthour, to be charged for
8671	8671	18 electricity generated by the initial clean coal
8672	8672	19 facility, (B) the projected impact on residential and
8673	8673	20 small business customers' bills over the life of the
8674	8674	21 sourcing agreements, and (C) the maximum allowable
8675	8675	22 return on equity for the project; and
8676	8676	23 (iv) Commission review. If the General Assembly
8677	8677	24 enacts authorizing legislation pursuant to
8678	8678	25 subparagraph (iii) approving a sourcing agreement, the
8679	8679	26 Commission shall, within 90 days of such enactment,
8680	8680
8681	8681
8682	8682
8683	8683
8684	8684
8685	8685	HB3779 - 241 - LRB104 11172 AAS 21254 b
8686	8686
8687	8687
8688	8688	HB3779- 242 -LRB104 11172 AAS 21254 b HB3779 - 242 - LRB104 11172 AAS 21254 b
8689	8689	HB3779 - 242 - LRB104 11172 AAS 21254 b
8690	8690	1 complete a review of such sourcing agreement. During
8691	8691	2 such time period, the Commission shall implement any
8692	8692	3 directive of the General Assembly, resolve any
8693	8693	4 disputes between the parties to the sourcing agreement
8694	8694	5 concerning the terms of such agreement, approve the
8695	8695	6 form of such agreement, and issue an order finding
8696	8696	7 that the sourcing agreement is prudent and reasonable.
8697	8697	8 The facility cost report shall be prepared as follows:
8698	8698	9 (A) The facility cost report shall be prepared by
8699	8699	10 duly licensed engineering and construction firms
8700	8700	11 detailing the estimated capital costs payable to one
8701	8701	12 or more contractors or suppliers for the engineering,
8702	8702	13 procurement and construction of the components
8703	8703	14 comprising the initial clean coal facility and the
8704	8704	15 estimated costs of operation and maintenance of the
8705	8705	16 facility. The facility cost report shall include:
8706	8706	17 (i) an estimate of the capital cost of the
8707	8707	18 core plant based on one or more front end
8708	8708	19 engineering and design studies for the
8709	8709	20 gasification island and related facilities. The
8710	8710	21 core plant shall include all civil, structural,
8711	8711	22 mechanical, electrical, control, and safety
8712	8712	23 systems.
8713	8713	24 (ii) an estimate of the capital cost of the
8714	8714	25 balance of the plant, including any capital costs
8715	8715	26 associated with sequestration of carbon dioxide
8716	8716
8717	8717
8718	8718
8719	8719
8720	8720
8721	8721	HB3779 - 242 - LRB104 11172 AAS 21254 b
8722	8722
8723	8723
8724	8724	HB3779- 243 -LRB104 11172 AAS 21254 b HB3779 - 243 - LRB104 11172 AAS 21254 b
8725	8725	HB3779 - 243 - LRB104 11172 AAS 21254 b
8726	8726	1 emissions and all interconnects and interfaces
8727	8727	2 required to operate the facility, such as
8728	8728	3 transmission of electricity, construction or
8729	8729	4 backfeed power supply, pipelines to transport
8730	8730	5 substitute natural gas or carbon dioxide, potable
8731	8731	6 water supply, natural gas supply, water supply,
8732	8732	7 water discharge, landfill, access roads, and coal
8733	8733	8 delivery.
8734	8734	9 The quoted construction costs shall be expressed
8735	8735	10 in nominal dollars as of the date that the quote is
8736	8736	11 prepared and shall include capitalized financing costs
8737	8737	12 during construction, taxes, insurance, and other
8738	8738	13 owner's costs, and an assumed escalation in materials
8739	8739	14 and labor beyond the date as of which the construction
8740	8740	15 cost quote is expressed.
8741	8741	16 (B) The front end engineering and design study for
8742	8742	17 the gasification island and the cost study for the
8743	8743	18 balance of plant shall include sufficient design work
8744	8744	19 to permit quantification of major categories of
8745	8745	20 materials, commodities and labor hours, and receipt of
8746	8746	21 quotes from vendors of major equipment required to
8747	8747	22 construct and operate the clean coal facility.
8748	8748	23 (C) The facility cost report shall also include an
8749	8749	24 operating and maintenance cost quote that will provide
8750	8750	25 the estimated cost of delivered fuel, personnel,
8751	8751	26 maintenance contracts, chemicals, catalysts,
8752	8752
8753	8753
8754	8754
8755	8755
8756	8756
8757	8757	HB3779 - 243 - LRB104 11172 AAS 21254 b
8758	8758
8759	8759
8760	8760	HB3779- 244 -LRB104 11172 AAS 21254 b HB3779 - 244 - LRB104 11172 AAS 21254 b
8761	8761	HB3779 - 244 - LRB104 11172 AAS 21254 b
8762	8762	1 consumables, spares, and other fixed and variable
8763	8763	2 operations and maintenance costs. The delivered fuel
8764	8764	3 cost estimate will be provided by a recognized third
8765	8765	4 party expert or experts in the fuel and transportation
8766	8766	5 industries. The balance of the operating and
8767	8767	6 maintenance cost quote, excluding delivered fuel
8768	8768	7 costs, will be developed based on the inputs provided
8769	8769	8 by duly licensed engineering and construction firms
8770	8770	9 performing the construction cost quote, potential
8771	8771	10 vendors under long-term service agreements and plant
8772	8772	11 operating agreements, or recognized third party plant
8773	8773	12 operator or operators.
8774	8774	13 The operating and maintenance cost quote
8775	8775	14 (including the cost of the front end engineering and
8776	8776	15 design study) shall be expressed in nominal dollars as
8777	8777	16 of the date that the quote is prepared and shall
8778	8778	17 include taxes, insurance, and other owner's costs, and
8779	8779	18 an assumed escalation in materials and labor beyond
8780	8780	19 the date as of which the operating and maintenance
8781	8781	20 cost quote is expressed.
8782	8782	21 (D) The facility cost report shall also include an
8783	8783	22 analysis of the initial clean coal facility's ability
8784	8784	23 to deliver power and energy into the applicable
8785	8785	24 regional transmission organization markets and an
8786	8786	25 analysis of the expected capacity factor for the
8787	8787	26 initial clean coal facility.
8788	8788
8789	8789
8790	8790
8791	8791
8792	8792
8793	8793	HB3779 - 244 - LRB104 11172 AAS 21254 b
8794	8794
8795	8795
8796	8796	HB3779- 245 -LRB104 11172 AAS 21254 b HB3779 - 245 - LRB104 11172 AAS 21254 b
8797	8797	HB3779 - 245 - LRB104 11172 AAS 21254 b
8798	8798	1 (E) Amounts paid to third parties unrelated to the
8799	8799	2 owner or owners of the initial clean coal facility to
8800	8800	3 prepare the core plant construction cost quote,
8801	8801	4 including the front end engineering and design study,
8802	8802	5 and the operating and maintenance cost quote will be
8803	8803	6 reimbursed through Coal Development Bonds.
8804	8804	7 (5) Re-powering and retrofitting coal-fired power
8805	8805	8 plants previously owned by Illinois utilities to qualify
8806	8806	9 as clean coal facilities. During the 2009 procurement
8807	8807	10 planning process and thereafter, the Agency and the
8808	8808	11 Commission shall consider sourcing agreements covering
8809	8809	12 electricity generated by power plants that were previously
8810	8810	13 owned by Illinois utilities and that have been or will be
8811	8811	14 converted into clean coal facilities, as defined by
8812	8812	15 Section 1-10 of this Act. Pursuant to such procurement
8813	8813	16 planning process, the owners of such facilities may
8814	8814	17 propose to the Agency sourcing agreements with utilities
8815	8815	18 and alternative retail electric suppliers required to
8816	8816	19 comply with subsection (d) of this Section and item (5) of
8817	8817	20 subsection (d) of Section 16-115 of the Public Utilities
8818	8818	21 Act, covering electricity generated by such facilities. In
8819	8819	22 the case of sourcing agreements that are power purchase
8820	8820	23 agreements, the contract price for electricity sales shall
8821	8821	24 be established on a cost of service basis. In the case of
8822	8822	25 sourcing agreements that are contracts for differences,
8823	8823	26 the contract price from which the reference price is
8824	8824
8825	8825
8826	8826
8827	8827
8828	8828
8829	8829	HB3779 - 245 - LRB104 11172 AAS 21254 b
8830	8830
8831	8831
8832	8832	HB3779- 246 -LRB104 11172 AAS 21254 b HB3779 - 246 - LRB104 11172 AAS 21254 b
8833	8833	HB3779 - 246 - LRB104 11172 AAS 21254 b
8834	8834	1 subtracted shall be established on a cost of service
8835	8835	2 basis. The Agency and the Commission may approve any such
8836	8836	3 utility sourcing agreements that do not exceed cost-based
8837	8837	4 benchmarks developed by the procurement administrator, in
8838	8838	5 consultation with the Commission staff, Agency staff and
8839	8839	6 the procurement monitor, subject to Commission review and
8840	8840	7 approval. The Commission shall have authority to inspect
8841	8841	8 all books and records associated with these clean coal
8842	8842	9 facilities during the term of any such contract.
8843	8843	10 (6) Costs incurred under this subsection (d) or
8844	8844	11 pursuant to a contract entered into under this subsection
8845	8845	12 (d) shall be deemed prudently incurred and reasonable in
8846	8846	13 amount and the electric utility shall be entitled to full
8847	8847	14 cost recovery pursuant to the tariffs filed with the
8848	8848	15 Commission.
8849	8849	16 (d-5) Zero emission standard.
8850	8850	17 (1) Beginning with the delivery year commencing on
8851	8851	18 June 1, 2017, the Agency shall, for electric utilities
8852	8852	19 that serve at least 100,000 retail customers in this
8853	8853	20 State, procure contracts with zero emission facilities
8854	8854	21 that are reasonably capable of generating cost-effective
8855	8855	22 zero emission credits in an amount approximately equal to
8856	8856	23 16% of the actual amount of electricity delivered by each
8857	8857	24 electric utility to retail customers in the State during
8858	8858	25 calendar year 2014. For an electric utility serving fewer
8859	8859	26 than 100,000 retail customers in this State that
8860	8860
8861	8861
8862	8862
8863	8863
8864	8864
8865	8865	HB3779 - 246 - LRB104 11172 AAS 21254 b
8866	8866
8867	8867
8868	8868	HB3779- 247 -LRB104 11172 AAS 21254 b HB3779 - 247 - LRB104 11172 AAS 21254 b
8869	8869	HB3779 - 247 - LRB104 11172 AAS 21254 b
8870	8870	1 requested, under Section 16-111.5 of the Public Utilities
8871	8871	2 Act, that the Agency procure power and energy for all or a
8872	8872	3 portion of the utility's Illinois load for the delivery
8873	8873	4 year commencing June 1, 2016, the Agency shall procure
8874	8874	5 contracts with zero emission facilities that are
8875	8875	6 reasonably capable of generating cost-effective zero
8876	8876	7 emission credits in an amount approximately equal to 16%
8877	8877	8 of the portion of power and energy to be procured by the
8878	8878	9 Agency for the utility. The duration of the contracts
8879	8879	10 procured under this subsection (d-5) shall be for a term
8880	8880	11 of 10 years ending May 31, 2027. The quantity of zero
8881	8881	12 emission credits to be procured under the contracts shall
8882	8882	13 be all of the zero emission credits generated by the zero
8883	8883	14 emission facility in each delivery year; however, if the
8884	8884	15 zero emission facility is owned by more than one entity,
8885	8885	16 then the quantity of zero emission credits to be procured
8886	8886	17 under the contracts shall be the amount of zero emission
8887	8887	18 credits that are generated from the portion of the zero
8888	8888	19 emission facility that is owned by the winning supplier.
8889	8889	20 The 16% value identified in this paragraph (1) is the
8890	8890	21 average of the percentage targets in subparagraph (B) of
8891	8891	22 paragraph (1) of subsection (c) of this Section for the 5
8892	8892	23 delivery years beginning June 1, 2017.
8893	8893	24 The procurement process shall be subject to the
8894	8894	25 following provisions:
8895	8895	26 (A) Those zero emission facilities that intend to
8896	8896
8897	8897
8898	8898
8899	8899
8900	8900
8901	8901	HB3779 - 247 - LRB104 11172 AAS 21254 b
8902	8902
8903	8903
8904	8904	HB3779- 248 -LRB104 11172 AAS 21254 b HB3779 - 248 - LRB104 11172 AAS 21254 b
8905	8905	HB3779 - 248 - LRB104 11172 AAS 21254 b
8906	8906	1 participate in the procurement shall submit to the
8907	8907	2 Agency the following eligibility information for each
8908	8908	3 zero emission facility on or before the date
8909	8909	4 established by the Agency:
8910	8910	5 (i) the in-service date and remaining useful
8911	8911	6 life of the zero emission facility;
8912	8912	7 (ii) the amount of power generated annually
8913	8913	8 for each of the years 2005 through 2015, and the
8914	8914	9 projected zero emission credits to be generated
8915	8915	10 over the remaining useful life of the zero
8916	8916	11 emission facility, which shall be used to
8917	8917	12 determine the capability of each facility;
8918	8918	13 (iii) the annual zero emission facility cost
8919	8919	14 projections, expressed on a per megawatthour
8920	8920	15 basis, over the next 6 delivery years, which shall
8921	8921	16 include the following: operation and maintenance
8922	8922	17 expenses; fully allocated overhead costs, which
8923	8923	18 shall be allocated using the methodology developed
8924	8924	19 by the Institute for Nuclear Power Operations;
8925	8925	20 fuel expenditures; non-fuel capital expenditures;
8926	8926	21 spent fuel expenditures; a return on working
8927	8927	22 capital; the cost of operational and market risks
8928	8928	23 that could be avoided by ceasing operation; and
8929	8929	24 any other costs necessary for continued
8930	8930	25 operations, provided that "necessary" means, for
8931	8931	26 purposes of this item (iii), that the costs could
8932	8932
8933	8933
8934	8934
8935	8935
8936	8936
8937	8937	HB3779 - 248 - LRB104 11172 AAS 21254 b
8938	8938
8939	8939
8940	8940	HB3779- 249 -LRB104 11172 AAS 21254 b HB3779 - 249 - LRB104 11172 AAS 21254 b
8941	8941	HB3779 - 249 - LRB104 11172 AAS 21254 b
8942	8942	1 reasonably be avoided only by ceasing operations
8943	8943	2 of the zero emission facility; and
8944	8944	3 (iv) a commitment to continue operating, for
8945	8945	4 the duration of the contract or contracts executed
8946	8946	5 under the procurement held under this subsection
8947	8947	6 (d-5), the zero emission facility that produces
8948	8948	7 the zero emission credits to be procured in the
8949	8949	8 procurement.
8950	8950	9 The information described in item (iii) of this
8951	8951	10 subparagraph (A) may be submitted on a confidential
8952	8952	11 basis and shall be treated and maintained by the
8953	8953	12 Agency, the procurement administrator, and the
8954	8954	13 Commission as confidential and proprietary and exempt
8955	8955	14 from disclosure under subparagraphs (a) and (g) of
8956	8956	15 paragraph (1) of Section 7 of the Freedom of
8957	8957	16 Information Act. The Office of Attorney General shall
8958	8958	17 have access to, and maintain the confidentiality of,
8959	8959	18 such information pursuant to Section 6.5 of the
8960	8960	19 Attorney General Act.
8961	8961	20 (B) The price for each zero emission credit
8962	8962	21 procured under this subsection (d-5) for each delivery
8963	8963	22 year shall be in an amount that equals the Social Cost
8964	8964	23 of Carbon, expressed on a price per megawatthour
8965	8965	24 basis. However, to ensure that the procurement remains
8966	8966	25 affordable to retail customers in this State if
8967	8967	26 electricity prices increase, the price in an
8968	8968
8969	8969
8970	8970
8971	8971
8972	8972
8973	8973	HB3779 - 249 - LRB104 11172 AAS 21254 b
8974	8974
8975	8975
8976	8976	HB3779- 250 -LRB104 11172 AAS 21254 b HB3779 - 250 - LRB104 11172 AAS 21254 b
8977	8977	HB3779 - 250 - LRB104 11172 AAS 21254 b
8978	8978	1 applicable delivery year shall be reduced below the
8979	8979	2 Social Cost of Carbon by the amount ("Price
8980	8980	3 Adjustment") by which the market price index for the
8981	8981	4 applicable delivery year exceeds the baseline market
8982	8982	5 price index for the consecutive 12-month period ending
8983	8983	6 May 31, 2016. If the Price Adjustment is greater than
8984	8984	7 or equal to the Social Cost of Carbon in an applicable
8985	8985	8 delivery year, then no payments shall be due in that
8986	8986	9 delivery year. The components of this calculation are
8987	8987	10 defined as follows:
8988	8988	11 (i) Social Cost of Carbon: The Social Cost of
8989	8989	12 Carbon is $16.50 per megawatthour, which is based
8990	8990	13 on the U.S. Interagency Working Group on Social
8991	8991	14 Cost of Carbon's price in the August 2016
8992	8992	15 Technical Update using a 3% discount rate,
8993	8993	16 adjusted for inflation for each year of the
8994	8994	17 program. Beginning with the delivery year
8995	8995	18 commencing June 1, 2023, the price per
8996	8996	19 megawatthour shall increase by $1 per
8997	8997	20 megawatthour, and continue to increase by an
8998	8998	21 additional $1 per megawatthour each delivery year
8999	8999	22 thereafter.
9000	9000	23 (ii) Baseline market price index: The baseline
9001	9001	24 market price index for the consecutive 12-month
9002	9002	25 period ending May 31, 2016 is $31.40 per
9003	9003	26 megawatthour, which is based on the sum of (aa)
9004	9004
9005	9005
9006	9006
9007	9007
9008	9008
9009	9009	HB3779 - 250 - LRB104 11172 AAS 21254 b
9010	9010
9011	9011
9012	9012	HB3779- 251 -LRB104 11172 AAS 21254 b HB3779 - 251 - LRB104 11172 AAS 21254 b
9013	9013	HB3779 - 251 - LRB104 11172 AAS 21254 b
9014	9014	1 the average day-ahead energy price across all
9015	9015	2 hours of such 12-month period at the PJM
9016	9016	3 Interconnection LLC Northern Illinois Hub, (bb)
9017	9017	4 50% multiplied by the Base Residual Auction, or
9018	9018	5 its successor, capacity price for the rest of the
9019	9019	6 RTO zone group determined by PJM Interconnection
9020	9020	7 LLC, divided by 24 hours per day, and (cc) 50%
9021	9021	8 multiplied by the Planning Resource Auction, or
9022	9022	9 its successor, capacity price for Zone 4
9023	9023	10 determined by the Midcontinent Independent System
9024	9024	11 Operator, Inc., divided by 24 hours per day.
9025	9025	12 (iii) Market price index: The market price
9026	9026	13 index for a delivery year shall be the sum of
9027	9027	14 projected energy prices and projected capacity
9028	9028	15 prices determined as follows:
9029	9029	16 (aa) Projected energy prices: the
9030	9030	17 projected energy prices for the applicable
9031	9031	18 delivery year shall be calculated once for the
9032	9032	19 year using the forward market price for the
9033	9033	20 PJM Interconnection, LLC Northern Illinois
9034	9034	21 Hub. The forward market price shall be
9035	9035	22 calculated as follows: the energy forward
9036	9036	23 prices for each month of the applicable
9037	9037	24 delivery year averaged for each trade date
9038	9038	25 during the calendar year immediately preceding
9039	9039	26 that delivery year to produce a single energy
9040	9040
9041	9041
9042	9042
9043	9043
9044	9044
9045	9045	HB3779 - 251 - LRB104 11172 AAS 21254 b
9046	9046
9047	9047
9048	9048	HB3779- 252 -LRB104 11172 AAS 21254 b HB3779 - 252 - LRB104 11172 AAS 21254 b
9049	9049	HB3779 - 252 - LRB104 11172 AAS 21254 b
9050	9050	1 forward price for the delivery year. The
9051	9051	2 forward market price calculation shall use
9052	9052	3 data published by the Intercontinental
9053	9053	4 Exchange, or its successor.
9054	9054	5 (bb) Projected capacity prices:
9055	9055	6 (I) For the delivery years commencing
9056	9056	7 June 1, 2017, June 1, 2018, and June 1,
9057	9057	8 2019, the projected capacity price shall
9058	9058	9 be equal to the sum of (1) 50% multiplied
9059	9059	10 by the Base Residual Auction, or its
9060	9060	11 successor, price for the rest of the RTO
9061	9061	12 zone group as determined by PJM
9062	9062	13 Interconnection LLC, divided by 24 hours
9063	9063	14 per day and, (2) 50% multiplied by the
9064	9064	15 resource auction price determined in the
9065	9065	16 resource auction administered by the
9066	9066	17 Midcontinent Independent System Operator,
9067	9067	18 Inc., in which the largest percentage of
9068	9068	19 load cleared for Local Resource Zone 4,
9069	9069	20 divided by 24 hours per day, and where
9070	9070	21 such price is determined by the
9071	9071	22 Midcontinent Independent System Operator,
9072	9072	23 Inc.
9073	9073	24 (II) For the delivery year commencing
9074	9074	25 June 1, 2020, and each year thereafter,
9075	9075	26 the projected capacity price shall be
9076	9076
9077	9077
9078	9078
9079	9079
9080	9080
9081	9081	HB3779 - 252 - LRB104 11172 AAS 21254 b
9082	9082
9083	9083
9084	9084	HB3779- 253 -LRB104 11172 AAS 21254 b HB3779 - 253 - LRB104 11172 AAS 21254 b
9085	9085	HB3779 - 253 - LRB104 11172 AAS 21254 b
9086	9086	1 equal to the sum of (1) 50% multiplied by
9087	9087	2 the Base Residual Auction, or its
9088	9088	3 successor, price for the ComEd zone as
9089	9089	4 determined by PJM Interconnection LLC,
9090	9090	5 divided by 24 hours per day, and (2) 50%
9091	9091	6 multiplied by the resource auction price
9092	9092	7 determined in the resource auction
9093	9093	8 administered by the Midcontinent
9094	9094	9 Independent System Operator, Inc., in
9095	9095	10 which the largest percentage of load
9096	9096	11 cleared for Local Resource Zone 4, divided
9097	9097	12 by 24 hours per day, and where such price
9098	9098	13 is determined by the Midcontinent
9099	9099	14 Independent System Operator, Inc.
9100	9100	15 For purposes of this subsection (d-5):
9101	9101	16 "Rest of the RTO" and "ComEd Zone" shall have
9102	9102	17 the meaning ascribed to them by PJM
9103	9103	18 Interconnection, LLC.
9104	9104	19 "RTO" means regional transmission
9105	9105	20 organization.
9106	9106	21 (C) No later than 45 days after June 1, 2017 (the
9107	9107	22 effective date of Public Act 99-906), the Agency shall
9108	9108	23 publish its proposed zero emission standard
9109	9109	24 procurement plan. The plan shall be consistent with
9110	9110	25 the provisions of this paragraph (1) and shall provide
9111	9111	26 that winning bids shall be selected based on public
9112	9112
9113	9113
9114	9114
9115	9115
9116	9116
9117	9117	HB3779 - 253 - LRB104 11172 AAS 21254 b
9118	9118
9119	9119
9120	9120	HB3779- 254 -LRB104 11172 AAS 21254 b HB3779 - 254 - LRB104 11172 AAS 21254 b
9121	9121	HB3779 - 254 - LRB104 11172 AAS 21254 b
9122	9122	1 interest criteria that include, but are not limited
9123	9123	2 to, minimizing carbon dioxide emissions that result
9124	9124	3 from electricity consumed in Illinois and minimizing
9125	9125	4 sulfur dioxide, nitrogen oxide, and particulate matter
9126	9126	5 emissions that adversely affect the citizens of this
9127	9127	6 State. In particular, the selection of winning bids
9128	9128	7 shall take into account the incremental environmental
9129	9129	8 benefits resulting from the procurement, such as any
9130	9130	9 existing environmental benefits that are preserved by
9131	9131	10 the procurements held under Public Act 99-906 and
9132	9132	11 would cease to exist if the procurements were not
9133	9133	12 held, including the preservation of zero emission
9134	9134	13 facilities. The plan shall also describe in detail how
9135	9135	14 each public interest factor shall be considered and
9136	9136	15 weighted in the bid selection process to ensure that
9137	9137	16 the public interest criteria are applied to the
9138	9138	17 procurement and given full effect.
9139	9139	18 For purposes of developing the plan, the Agency
9140	9140	19 shall consider any reports issued by a State agency,
9141	9141	20 board, or commission under House Resolution 1146 of
9142	9142	21 the 98th General Assembly and paragraph (4) of
9143	9143	22 subsection (d) of this Section, as well as publicly
9144	9144	23 available analyses and studies performed by or for
9145	9145	24 regional transmission organizations that serve the
9146	9146	25 State and their independent market monitors.
9147	9147	26 Upon publishing of the zero emission standard
9148	9148
9149	9149
9150	9150
9151	9151
9152	9152
9153	9153	HB3779 - 254 - LRB104 11172 AAS 21254 b
9154	9154
9155	9155
9156	9156	HB3779- 255 -LRB104 11172 AAS 21254 b HB3779 - 255 - LRB104 11172 AAS 21254 b
9157	9157	HB3779 - 255 - LRB104 11172 AAS 21254 b
9158	9158	1 procurement plan, copies of the plan shall be posted
9159	9159	2 and made publicly available on the Agency's website.
9160	9160	3 All interested parties shall have 10 days following
9161	9161	4 the date of posting to provide comment to the Agency on
9162	9162	5 the plan. All comments shall be posted to the Agency's
9163	9163	6 website. Following the end of the comment period, but
9164	9164	7 no more than 60 days later than June 1, 2017 (the
9165	9165	8 effective date of Public Act 99-906), the Agency shall
9166	9166	9 revise the plan as necessary based on the comments
9167	9167	10 received and file its zero emission standard
9168	9168	11 procurement plan with the Commission.
9169	9169	12 If the Commission determines that the plan will
9170	9170	13 result in the procurement of cost-effective zero
9171	9171	14 emission credits, then the Commission shall, after
9172	9172	15 notice and hearing, but no later than 45 days after the
9173	9173	16 Agency filed the plan, approve the plan or approve
9174	9174	17 with modification. For purposes of this subsection
9175	9175	18 (d-5), "cost effective" means the projected costs of
9176	9176	19 procuring zero emission credits from zero emission
9177	9177	20 facilities do not cause the limit stated in paragraph
9178	9178	21 (2) of this subsection to be exceeded.
9179	9179	22 (C-5) As part of the Commission's review and
9180	9180	23 acceptance or rejection of the procurement results,
9181	9181	24 the Commission shall, in its public notice of
9182	9182	25 successful bidders:
9183	9183	26 (i) identify how the winning bids satisfy the
9184	9184
9185	9185
9186	9186
9187	9187
9188	9188
9189	9189	HB3779 - 255 - LRB104 11172 AAS 21254 b
9190	9190
9191	9191
9192	9192	HB3779- 256 -LRB104 11172 AAS 21254 b HB3779 - 256 - LRB104 11172 AAS 21254 b
9193	9193	HB3779 - 256 - LRB104 11172 AAS 21254 b
9194	9194	1 public interest criteria described in subparagraph
9195	9195	2 (C) of this paragraph (1) of minimizing carbon
9196	9196	3 dioxide emissions that result from electricity
9197	9197	4 consumed in Illinois and minimizing sulfur
9198	9198	5 dioxide, nitrogen oxide, and particulate matter
9199	9199	6 emissions that adversely affect the citizens of
9200	9200	7 this State;
9201	9201	8 (ii) specifically address how the selection of
9202	9202	9 winning bids takes into account the incremental
9203	9203	10 environmental benefits resulting from the
9204	9204	11 procurement, including any existing environmental
9205	9205	12 benefits that are preserved by the procurements
9206	9206	13 held under Public Act 99-906 and would have ceased
9207	9207	14 to exist if the procurements had not been held,
9208	9208	15 such as the preservation of zero emission
9209	9209	16 facilities;
9210	9210	17 (iii) quantify the environmental benefit of
9211	9211	18 preserving the resources identified in item (ii)
9212	9212	19 of this subparagraph (C-5), including the
9213	9213	20 following:
9214	9214	21 (aa) the value of avoided greenhouse gas
9215	9215	22 emissions measured as the product of the zero
9216	9216	23 emission facilities' output over the contract
9217	9217	24 term multiplied by the U.S. Environmental
9218	9218	25 Protection Agency eGrid subregion carbon
9219	9219	26 dioxide emission rate and the U.S. Interagency
9220	9220
9221	9221
9222	9222
9223	9223
9224	9224
9225	9225	HB3779 - 256 - LRB104 11172 AAS 21254 b
9226	9226
9227	9227
9228	9228	HB3779- 257 -LRB104 11172 AAS 21254 b HB3779 - 257 - LRB104 11172 AAS 21254 b
9229	9229	HB3779 - 257 - LRB104 11172 AAS 21254 b
9230	9230	1 Working Group on Social Cost of Carbon's price
9231	9231	2 in the August 2016 Technical Update using a 3%
9232	9232	3 discount rate, adjusted for inflation for each
9233	9233	4 delivery year; and
9234	9234	5 (bb) the costs of replacement with other
9235	9235	6 zero carbon dioxide resources, including wind
9236	9236	7 and photovoltaic, based upon the simple
9237	9237	8 average of the following:
9238	9238	9 (I) the price, or if there is more
9239	9239	10 than one price, the average of the prices,
9240	9240	11 paid for renewable energy credits from new
9241	9241	12 utility-scale wind projects in the
9242	9242	13 procurement events specified in item (i)
9243	9243	14 of subparagraph (G) of paragraph (1) of
9244	9244	15 subsection (c) of this Section; and
9245	9245	16 (II) the price, or if there is more
9246	9246	17 than one price, the average of the prices,
9247	9247	18 paid for renewable energy credits from new
9248	9248	19 utility-scale solar projects and
9249	9249	20 brownfield site photovoltaic projects in
9250	9250	21 the procurement events specified in item
9251	9251	22 (ii) of subparagraph (G) of paragraph (1)
9252	9252	23 of subsection (c) of this Section and,
9253	9253	24 after January 1, 2015, renewable energy
9254	9254	25 credits from photovoltaic distributed
9255	9255	26 generation projects in procurement events
9256	9256
9257	9257
9258	9258
9259	9259
9260	9260
9261	9261	HB3779 - 257 - LRB104 11172 AAS 21254 b
9262	9262
9263	9263
9264	9264	HB3779- 258 -LRB104 11172 AAS 21254 b HB3779 - 258 - LRB104 11172 AAS 21254 b
9265	9265	HB3779 - 258 - LRB104 11172 AAS 21254 b
9266	9266	1 held under subsection (c) of this Section.
9267	9267	2 Each utility shall enter into binding contractual
9268	9268	3 arrangements with the winning suppliers.
9269	9269	4 The procurement described in this subsection
9270	9270	5 (d-5), including, but not limited to, the execution of
9271	9271	6 all contracts procured, shall be completed no later
9272	9272	7 than May 10, 2017. Based on the effective date of
9273	9273	8 Public Act 99-906, the Agency and Commission may, as
9274	9274	9 appropriate, modify the various dates and timelines
9275	9275	10 under this subparagraph and subparagraphs (C) and (D)
9276	9276	11 of this paragraph (1). The procurement and plan
9277	9277	12 approval processes required by this subsection (d-5)
9278	9278	13 shall be conducted in conjunction with the procurement
9279	9279	14 and plan approval processes required by subsection (c)
9280	9280	15 of this Section and Section 16-111.5 of the Public
9281	9281	16 Utilities Act, to the extent practicable.
9282	9282	17 Notwithstanding whether a procurement event is
9283	9283	18 conducted under Section 16-111.5 of the Public
9284	9284	19 Utilities Act, the Agency shall immediately initiate a
9285	9285	20 procurement process on June 1, 2017 (the effective
9286	9286	21 date of Public Act 99-906).
9287	9287	22 (D) Following the procurement event described in
9288	9288	23 this paragraph (1) and consistent with subparagraph
9289	9289	24 (B) of this paragraph (1), the Agency shall calculate
9290	9290	25 the payments to be made under each contract for the
9291	9291	26 next delivery year based on the market price index for
9292	9292
9293	9293
9294	9294
9295	9295
9296	9296
9297	9297	HB3779 - 258 - LRB104 11172 AAS 21254 b
9298	9298
9299	9299
9300	9300	HB3779- 259 -LRB104 11172 AAS 21254 b HB3779 - 259 - LRB104 11172 AAS 21254 b
9301	9301	HB3779 - 259 - LRB104 11172 AAS 21254 b
9302	9302	1 that delivery year. The Agency shall publish the
9303	9303	2 payment calculations no later than May 25, 2017 and
9304	9304	3 every May 25 thereafter.
9305	9305	4 (E) Notwithstanding the requirements of this
9306	9306	5 subsection (d-5), the contracts executed under this
9307	9307	6 subsection (d-5) shall provide that the zero emission
9308	9308	7 facility may, as applicable, suspend or terminate
9309	9309	8 performance under the contracts in the following
9310	9310	9 instances:
9311	9311	10 (i) A zero emission facility shall be excused
9312	9312	11 from its performance under the contract for any
9313	9313	12 cause beyond the control of the resource,
9314	9314	13 including, but not restricted to, acts of God,
9315	9315	14 flood, drought, earthquake, storm, fire,
9316	9316	15 lightning, epidemic, war, riot, civil disturbance
9317	9317	16 or disobedience, labor dispute, labor or material
9318	9318	17 shortage, sabotage, acts of public enemy,
9319	9319	18 explosions, orders, regulations or restrictions
9320	9320	19 imposed by governmental, military, or lawfully
9321	9321	20 established civilian authorities, which, in any of
9322	9322	21 the foregoing cases, by exercise of commercially
9323	9323	22 reasonable efforts the zero emission facility
9324	9324	23 could not reasonably have been expected to avoid,
9325	9325	24 and which, by the exercise of commercially
9326	9326	25 reasonable efforts, it has been unable to
9327	9327	26 overcome. In such event, the zero emission
9328	9328
9329	9329
9330	9330
9331	9331
9332	9332
9333	9333	HB3779 - 259 - LRB104 11172 AAS 21254 b
9334	9334
9335	9335
9336	9336	HB3779- 260 -LRB104 11172 AAS 21254 b HB3779 - 260 - LRB104 11172 AAS 21254 b
9337	9337	HB3779 - 260 - LRB104 11172 AAS 21254 b
9338	9338	1 facility shall be excused from performance for the
9339	9339	2 duration of the event, including, but not limited
9340	9340	3 to, delivery of zero emission credits, and no
9341	9341	4 payment shall be due to the zero emission facility
9342	9342	5 during the duration of the event.
9343	9343	6 (ii) A zero emission facility shall be
9344	9344	7 permitted to terminate the contract if legislation
9345	9345	8 is enacted into law by the General Assembly that
9346	9346	9 imposes or authorizes a new tax, special
9347	9347	10 assessment, or fee on the generation of
9348	9348	11 electricity, the ownership or leasehold of a
9349	9349	12 generating unit, or the privilege or occupation of
9350	9350	13 such generation, ownership, or leasehold of
9351	9351	14 generation units by a zero emission facility.
9352	9352	15 However, the provisions of this item (ii) do not
9353	9353	16 apply to any generally applicable tax, special
9354	9354	17 assessment or fee, or requirements imposed by
9355	9355	18 federal law.
9356	9356	19 (iii) A zero emission facility shall be
9357	9357	20 permitted to terminate the contract in the event
9358	9358	21 that the resource requires capital expenditures in
9359	9359	22 excess of $40,000,000 that were neither known nor
9360	9360	23 reasonably foreseeable at the time it executed the
9361	9361	24 contract and that a prudent owner or operator of
9362	9362	25 such resource would not undertake.
9363	9363	26 (iv) A zero emission facility shall be
9364	9364
9365	9365
9366	9366
9367	9367
9368	9368
9369	9369	HB3779 - 260 - LRB104 11172 AAS 21254 b
9370	9370
9371	9371
9372	9372	HB3779- 261 -LRB104 11172 AAS 21254 b HB3779 - 261 - LRB104 11172 AAS 21254 b
9373	9373	HB3779 - 261 - LRB104 11172 AAS 21254 b
9374	9374	1 permitted to terminate the contract in the event
9375	9375	2 the Nuclear Regulatory Commission terminates the
9376	9376	3 resource's license.
9377	9377	4 (F) If the zero emission facility elects to
9378	9378	5 terminate a contract under subparagraph (E) of this
9379	9379	6 paragraph (1), then the Commission shall reopen the
9380	9380	7 docket in which the Commission approved the zero
9381	9381	8 emission standard procurement plan under subparagraph
9382	9382	9 (C) of this paragraph (1) and, after notice and
9383	9383	10 hearing, enter an order acknowledging the contract
9384	9384	11 termination election if such termination is consistent
9385	9385	12 with the provisions of this subsection (d-5).
9386	9386	13 (2) For purposes of this subsection (d-5), the amount
9387	9387	14 paid per kilowatthour means the total amount paid for
9388	9388	15 electric service expressed on a per kilowatthour basis.
9389	9389	16 For purposes of this subsection (d-5), the total amount
9390	9390	17 paid for electric service includes, without limitation,
9391	9391	18 amounts paid for supply, transmission, distribution,
9392	9392	19 surcharges, and add-on taxes.
9393	9393	20 Notwithstanding the requirements of this subsection
9394	9394	21 (d-5), the contracts executed under this subsection (d-5)
9395	9395	22 shall provide that the total of zero emission credits
9396	9396	23 procured under a procurement plan shall be subject to the
9397	9397	24 limitations of this paragraph (2). For each delivery year,
9398	9398	25 the contractual volume receiving payments in such year
9399	9399	26 shall be reduced for all retail customers based on the
9400	9400
9401	9401
9402	9402
9403	9403
9404	9404
9405	9405	HB3779 - 261 - LRB104 11172 AAS 21254 b
9406	9406
9407	9407
9408	9408	HB3779- 262 -LRB104 11172 AAS 21254 b HB3779 - 262 - LRB104 11172 AAS 21254 b
9409	9409	HB3779 - 262 - LRB104 11172 AAS 21254 b
9410	9410	1 amount necessary to limit the net increase that delivery
9411	9411	2 year to the costs of those credits included in the amounts
9412	9412	3 paid by eligible retail customers in connection with
9413	9413	4 electric service to no more than 1.65% of the amount paid
9414	9414	5 per kilowatthour by eligible retail customers during the
9415	9415	6 year ending May 31, 2009. The result of this computation
9416	9416	7 shall apply to and reduce the procurement for all retail
9417	9417	8 customers, and all those customers shall pay the same
9418	9418	9 single, uniform cents per kilowatthour charge under
9419	9419	10 subsection (k) of Section 16-108 of the Public Utilities
9420	9420	11 Act. To arrive at a maximum dollar amount of zero emission
9421	9421	12 credits to be paid for the particular delivery year, the
9422	9422	13 resulting per kilowatthour amount shall be applied to the
9423	9423	14 actual amount of kilowatthours of electricity delivered by
9424	9424	15 the electric utility in the delivery year immediately
9425	9425	16 prior to the procurement, to all retail customers in its
9426	9426	17 service territory. Unpaid contractual volume for any
9427	9427	18 delivery year shall be paid in any subsequent delivery
9428	9428	19 year in which such payments can be made without exceeding
9429	9429	20 the amount specified in this paragraph (2). The
9430	9430	21 calculations required by this paragraph (2) shall be made
9431	9431	22 only once for each procurement plan year. Once the
9432	9432	23 determination as to the amount of zero emission credits to
9433	9433	24 be paid is made based on the calculations set forth in this
9434	9434	25 paragraph (2), no subsequent rate impact determinations
9435	9435	26 shall be made and no adjustments to those contract amounts
9436	9436
9437	9437
9438	9438
9439	9439
9440	9440
9441	9441	HB3779 - 262 - LRB104 11172 AAS 21254 b
9442	9442
9443	9443
9444	9444	HB3779- 263 -LRB104 11172 AAS 21254 b HB3779 - 263 - LRB104 11172 AAS 21254 b
9445	9445	HB3779 - 263 - LRB104 11172 AAS 21254 b
9446	9446	1 shall be allowed. All costs incurred under those contracts
9447	9447	2 and in implementing this subsection (d-5) shall be
9448	9448	3 recovered by the electric utility as provided in this
9449	9449	4 Section.
9450	9450	5 No later than June 30, 2019, the Commission shall
9451	9451	6 review the limitation on the amount of zero emission
9452	9452	7 credits procured under this subsection (d-5) and report to
9453	9453	8 the General Assembly its findings as to whether that
9454	9454	9 limitation unduly constrains the procurement of
9455	9455	10 cost-effective zero emission credits.
9456	9456	11 (3) Six years after the execution of a contract under
9457	9457	12 this subsection (d-5), the Agency shall determine whether
9458	9458	13 the actual zero emission credit payments received by the
9459	9459	14 supplier over the 6-year period exceed the Average ZEC
9460	9460	15 Payment. In addition, at the end of the term of a contract
9461	9461	16 executed under this subsection (d-5), or at the time, if
9462	9462	17 any, a zero emission facility's contract is terminated
9463	9463	18 under subparagraph (E) of paragraph (1) of this subsection
9464	9464	19 (d-5), then the Agency shall determine whether the actual
9465	9465	20 zero emission credit payments received by the supplier
9466	9466	21 over the term of the contract exceed the Average ZEC
9467	9467	22 Payment, after taking into account any amounts previously
9468	9468	23 credited back to the utility under this paragraph (3). If
9469	9469	24 the Agency determines that the actual zero emission credit
9470	9470	25 payments received by the supplier over the relevant period
9471	9471	26 exceed the Average ZEC Payment, then the supplier shall
9472	9472
9473	9473
9474	9474
9475	9475
9476	9476
9477	9477	HB3779 - 263 - LRB104 11172 AAS 21254 b
9478	9478
9479	9479
9480	9480	HB3779- 264 -LRB104 11172 AAS 21254 b HB3779 - 264 - LRB104 11172 AAS 21254 b
9481	9481	HB3779 - 264 - LRB104 11172 AAS 21254 b
9482	9482	1 credit the difference back to the utility. The amount of
9483	9483	2 the credit shall be remitted to the applicable electric
9484	9484	3 utility no later than 120 days after the Agency's
9485	9485	4 determination, which the utility shall reflect as a credit
9486	9486	5 on its retail customer bills as soon as practicable;
9487	9487	6 however, the credit remitted to the utility shall not
9488	9488	7 exceed the total amount of payments received by the
9489	9489	8 facility under its contract.
9490	9490	9 For purposes of this Section, the Average ZEC Payment
9491	9491	10 shall be calculated by multiplying the quantity of zero
9492	9492	11 emission credits delivered under the contract times the
9493	9493	12 average contract price. The average contract price shall
9494	9494	13 be determined by subtracting the amount calculated under
9495	9495	14 subparagraph (B) of this paragraph (3) from the amount
9496	9496	15 calculated under subparagraph (A) of this paragraph (3),
9497	9497	16 as follows:
9498	9498	17 (A) The average of the Social Cost of Carbon, as
9499	9499	18 defined in subparagraph (B) of paragraph (1) of this
9500	9500	19 subsection (d-5), during the term of the contract.
9501	9501	20 (B) The average of the market price indices, as
9502	9502	21 defined in subparagraph (B) of paragraph (1) of this
9503	9503	22 subsection (d-5), during the term of the contract,
9504	9504	23 minus the baseline market price index, as defined in
9505	9505	24 subparagraph (B) of paragraph (1) of this subsection
9506	9506	25 (d-5).
9507	9507	26 If the subtraction yields a negative number, then the
9508	9508
9509	9509
9510	9510
9511	9511
9512	9512
9513	9513	HB3779 - 264 - LRB104 11172 AAS 21254 b
9514	9514
9515	9515
9516	9516	HB3779- 265 -LRB104 11172 AAS 21254 b HB3779 - 265 - LRB104 11172 AAS 21254 b
9517	9517	HB3779 - 265 - LRB104 11172 AAS 21254 b
9518	9518	1 Average ZEC Payment shall be zero.
9519	9519	2 (4) Cost-effective zero emission credits procured from
9520	9520	3 zero emission facilities shall satisfy the applicable
9521	9521	4 definitions set forth in Section 1-10 of this Act.
9522	9522	5 (5) The electric utility shall retire all zero
9523	9523	6 emission credits used to comply with the requirements of
9524	9524	7 this subsection (d-5).
9525	9525	8 (6) Electric utilities shall be entitled to recover
9526	9526	9 all of the costs associated with the procurement of zero
9527	9527	10 emission credits through an automatic adjustment clause
9528	9528	11 tariff in accordance with subsection (k) and (m) of
9529	9529	12 Section 16-108 of the Public Utilities Act, and the
9530	9530	13 contracts executed under this subsection (d-5) shall
9531	9531	14 provide that the utilities' payment obligations under such
9532	9532	15 contracts shall be reduced if an adjustment is required
9533	9533	16 under subsection (m) of Section 16-108 of the Public
9534	9534	17 Utilities Act.
9535	9535	18 (7) This subsection (d-5) shall become inoperative on
9536	9536	19 January 1, 2028.
9537	9537	20 (d-10) Nuclear Plant Assistance; carbon mitigation
9538	9538	21 credits.
9539	9539	22 (1) The General Assembly finds:
9540	9540	23 (A) The health, welfare, and prosperity of all
9541	9541	24 Illinois citizens require that the State of Illinois act
9542	9542	25 to avoid and not increase carbon emissions from electric
9543	9543	26 generation sources while continuing to ensure affordable,
9544	9544
9545	9545
9546	9546
9547	9547
9548	9548
9549	9549	HB3779 - 265 - LRB104 11172 AAS 21254 b
9550	9550
9551	9551
9552	9552	HB3779- 266 -LRB104 11172 AAS 21254 b HB3779 - 266 - LRB104 11172 AAS 21254 b
9553	9553	HB3779 - 266 - LRB104 11172 AAS 21254 b
9554	9554	1 stable, and reliable electricity to all citizens.
9555	9555	2 (B) Absent immediate action by the State to preserve
9556	9556	3 existing carbon-free energy resources, those resources may
9557	9557	4 retire, and the electric generation needs of Illinois'
9558	9558	5 retail customers may be met instead by facilities that
9559	9559	6 emit significant amounts of carbon pollution and other
9560	9560	7 harmful air pollutants at a high social and economic cost
9561	9561	8 until Illinois is able to develop other forms of clean
9562	9562	9 energy.
9563	9563	10 (C) The General Assembly finds that nuclear power
9564	9564	11 generation is necessary for the State's transition to 100%
9565	9565	12 clean energy, and ensuring continued operation of nuclear
9566	9566	13 plants advances environmental and public health interests
9567	9567	14 through providing carbon-free electricity while reducing
9568	9568	15 the air pollution profile of the Illinois energy
9569	9569	16 generation fleet.
9570	9570	17 (D) The clean energy attributes of nuclear generation
9571	9571	18 facilities support the State in its efforts to achieve
9572	9572	19 100% clean energy.
9573	9573	20 (E) The State currently invests in various forms of
9574	9574	21 clean energy, including, but not limited to, renewable
9575	9575	22 energy, energy efficiency, and low-emission vehicles,
9576	9576	23 among others.
9577	9577	24 (F) The Environmental Protection Agency commissioned
9578	9578	25 an independent audit which provided a detailed assessment
9579	9579	26 of the financial condition of the Illinois nuclear fleet
9580	9580
9581	9581
9582	9582
9583	9583
9584	9584
9585	9585	HB3779 - 266 - LRB104 11172 AAS 21254 b
9586	9586
9587	9587
9588	9588	HB3779- 267 -LRB104 11172 AAS 21254 b HB3779 - 267 - LRB104 11172 AAS 21254 b
9589	9589	HB3779 - 267 - LRB104 11172 AAS 21254 b
9590	9590	1 to evaluate its financial viability and whether the
9591	9591	2 environmental benefits of such resources were at risk. The
9592	9592	3 report identified the risk of losing the environmental
9593	9593	4 benefits of several specific nuclear units. The report
9594	9594	5 also identified that the LaSalle County Generating Station
9595	9595	6 will continue to operate through 2026 and therefore is not
9596	9596	7 eligible to participate in the carbon mitigation credit
9597	9597	8 program.
9598	9598	9 (G) Nuclear plants provide carbon-free energy, which
9599	9599	10 helps to avoid many health-related negative impacts for
9600	9600	11 Illinois residents.
9601	9601	12 (H) The procurement of carbon mitigation credits
9602	9602	13 representing the environmental benefits of carbon-free
9603	9603	14 generation will further the State's efforts at achieving
9604	9604	15 100% clean energy and decarbonizing the electricity sector
9605	9605	16 in a safe, reliable, and affordable manner. Further, the
9606	9606	17 procurement of carbon emission credits will enhance the
9607	9607	18 health and welfare of Illinois residents through decreased
9608	9608	19 reliance on more highly polluting generation.
9609	9609	20 (I) The General Assembly therefore finds it necessary
9610	9610	21 to establish carbon mitigation credits to ensure decreased
9611	9611	22 reliance on more carbon-intensive energy resources, for
9612	9612	23 transitioning to a fully decarbonized electricity sector,
9613	9613	24 and to help ensure health and welfare of the State's
9614	9614	25 residents.
9615	9615	26 (2) As used in this subsection:
9616	9616
9617	9617
9618	9618
9619	9619
9620	9620
9621	9621	HB3779 - 267 - LRB104 11172 AAS 21254 b
9622	9622
9623	9623
9624	9624	HB3779- 268 -LRB104 11172 AAS 21254 b HB3779 - 268 - LRB104 11172 AAS 21254 b
9625	9625	HB3779 - 268 - LRB104 11172 AAS 21254 b
9626	9626	1 "Baseline costs" means costs used to establish a customer
9627	9627	2 protection cap that have been evaluated through an independent
9628	9628	3 audit of a carbon-free energy resource conducted by the
9629	9629	4 Environmental Protection Agency that evaluated projected
9630	9630	5 annual costs for operation and maintenance expenses; fully
9631	9631	6 allocated overhead costs, which shall be allocated using the
9632	9632	7 methodology developed by the Institute for Nuclear Power
9633	9633	8 Operations; fuel expenditures; nonfuel capital expenditures;
9634	9634	9 spent fuel expenditures; a return on working capital; the cost
9635	9635	10 of operational and market risks that could be avoided by
9636	9636	11 ceasing operation; and any other costs necessary for continued
9637	9637	12 operations, provided that "necessary" means, for purposes of
9638	9638	13 this definition, that the costs could reasonably be avoided
9639	9639	14 only by ceasing operations of the carbon-free energy resource.
9640	9640	15 "Carbon mitigation credit" means a tradable credit that
9641	9641	16 represents the carbon emission reduction attributes of one
9642	9642	17 megawatt-hour of energy produced from a carbon-free energy
9643	9643	18 resource.
9644	9644	19 "Carbon-free energy resource" means a generation facility
9645	9645	20 that: (1) is fueled by nuclear power; and (2) is
9646	9646	21 interconnected to PJM Interconnection, LLC.
9647	9647	22 (3) Procurement.
9648	9648	23 (A) Beginning with the delivery year commencing on
9649	9649	24 June 1, 2022, the Agency shall, for electric utilities
9650	9650	25 serving at least 3,000,000 retail customers in the State,
9651	9651	26 seek to procure contracts for no more than approximately
9652	9652
9653	9653
9654	9654
9655	9655
9656	9656
9657	9657	HB3779 - 268 - LRB104 11172 AAS 21254 b
9658	9658
9659	9659
9660	9660	HB3779- 269 -LRB104 11172 AAS 21254 b HB3779 - 269 - LRB104 11172 AAS 21254 b
9661	9661	HB3779 - 269 - LRB104 11172 AAS 21254 b
9662	9662	1 54,500,000 cost-effective carbon mitigation credits from
9663	9663	2 carbon-free energy resources because such credits are
9664	9664	3 necessary to support current levels of carbon-free energy
9665	9665	4 generation and ensure the State meets its carbon dioxide
9666	9666	5 emissions reduction goals. The Agency shall not make a
9667	9667	6 partial award of a contract for carbon mitigation credits
9668	9668	7 covering a fractional amount of a carbon-free energy
9669	9669	8 resource's projected output.
9670	9670	9 (B) Each carbon-free energy resource that intends to
9671	9671	10 participate in a procurement shall be required to submit
9672	9672	11 to the Agency the following information for the resource
9673	9673	12 on or before the date established by the Agency:
9674	9674	13 (i) the in-service date and remaining useful life
9675	9675	14 of the carbon-free energy resource;
9676	9676	15 (ii) the amount of power generated annually for
9677	9677	16 each of the past 10 years, which shall be used to
9678	9678	17 determine the capability of each facility;
9679	9679	18 (iii) a commitment to be reflected in any contract
9680	9680	19 entered into pursuant to this subsection (d-10) to
9681	9681	20 continue operating the carbon-free energy resource at
9682	9682	21 a capacity factor of at least 88% annually on average
9683	9683	22 for the duration of the contract or contracts executed
9684	9684	23 under the procurement held under this subsection
9685	9685	24 (d-10), except in an instance described in
9686	9686	25 subparagraph (E) of paragraph (1) of subsection (d-5)
9687	9687	26 of this Section or made impracticable as a result of
9688	9688
9689	9689
9690	9690
9691	9691
9692	9692
9693	9693	HB3779 - 269 - LRB104 11172 AAS 21254 b
9694	9694
9695	9695
9696	9696	HB3779- 270 -LRB104 11172 AAS 21254 b HB3779 - 270 - LRB104 11172 AAS 21254 b
9697	9697	HB3779 - 270 - LRB104 11172 AAS 21254 b
9698	9698	1 compliance with law or regulation;
9699	9699	2 (iv) financial need and the risk of loss of the
9700	9700	3 environmental benefits of such resource, which shall
9701	9701	4 include the following information:
9702	9702	5 (I) the carbon-free energy resource's cost
9703	9703	6 projections, expressed on a per megawatt-hour
9704	9704	7 basis, over the next 5 delivery years, which shall
9705	9705	8 include the following: operation and maintenance
9706	9706	9 expenses; fully allocated overhead costs, which
9707	9707	10 shall be allocated using the methodology developed
9708	9708	11 by the Institute for Nuclear Power Operations;
9709	9709	12 fuel expenditures; nonfuel capital expenditures;
9710	9710	13 spent fuel expenditures; a return on working
9711	9711	14 capital; the cost of operational and market risks
9712	9712	15 that could be avoided by ceasing operation; and
9713	9713	16 any other costs necessary for continued
9714	9714	17 operations, provided that "necessary" means, for
9715	9715	18 purposes of this subitem (I), that the costs could
9716	9716	19 reasonably be avoided only by ceasing operations
9717	9717	20 of the carbon-free energy resource; and
9718	9718	21 (II) the carbon-free energy resource's revenue
9719	9719	22 projections, including energy, capacity, ancillary
9720	9720	23 services, any other direct State support, known or
9721	9721	24 anticipated federal attribute credits, known or
9722	9722	25 anticipated tax credits, and any other direct
9723	9723	26 federal support.
9724	9724
9725	9725
9726	9726
9727	9727
9728	9728
9729	9729	HB3779 - 270 - LRB104 11172 AAS 21254 b
9730	9730
9731	9731
9732	9732	HB3779- 271 -LRB104 11172 AAS 21254 b HB3779 - 271 - LRB104 11172 AAS 21254 b
9733	9733	HB3779 - 271 - LRB104 11172 AAS 21254 b
9734	9734	1 The information described in this subparagraph (B) may
9735	9735	2 be submitted on a confidential basis and shall be treated
9736	9736	3 and maintained by the Agency, the procurement
9737	9737	4 administrator, and the Commission as confidential and
9738	9738	5 proprietary and exempt from disclosure under subparagraphs
9739	9739	6 (a) and (g) of paragraph (1) of Section 7 of the Freedom of
9740	9740	7 Information Act. The Office of the Attorney General shall
9741	9741	8 have access to, and maintain the confidentiality of, such
9742	9742	9 information pursuant to Section 6.5 of the Attorney
9743	9743	10 General Act.
9744	9744	11 (C) The Agency shall solicit bids for the contracts
9745	9745	12 described in this subsection (d-10) from carbon-free
9746	9746	13 energy resources that have satisfied the requirements of
9747	9747	14 subparagraph (B) of this paragraph (3). The contracts
9748	9748	15 procured pursuant to a procurement event shall reflect,
9749	9749	16 and be subject to, the following terms, requirements, and
9750	9750	17 limitations:
9751	9751	18 (i) Contracts are for delivery of carbon
9752	9752	19 mitigation credits, and are not energy or capacity
9753	9753	20 sales contracts requiring physical delivery. Pursuant
9754	9754	21 to item (iii), contract payments shall fully deduct
9755	9755	22 the value of any monetized federal production tax
9756	9756	23 credits, credits issued pursuant to a federal clean
9757	9757	24 energy standard, and other federal credits if
9758	9758	25 applicable.
9759	9759	26 (ii) Contracts for carbon mitigation credits shall
9760	9760
9761	9761
9762	9762
9763	9763
9764	9764
9765	9765	HB3779 - 271 - LRB104 11172 AAS 21254 b
9766	9766
9767	9767
9768	9768	HB3779- 272 -LRB104 11172 AAS 21254 b HB3779 - 272 - LRB104 11172 AAS 21254 b
9769	9769	HB3779 - 272 - LRB104 11172 AAS 21254 b
9770	9770	1 commence with the delivery year beginning on June 1,
9771	9771	2 2022 and shall be for a term of 5 delivery years
9772	9772	3 concluding on May 31, 2027.
9773	9773	4 (iii) The price per carbon mitigation credit to be
9774	9774	5 paid under a contract for a given delivery year shall
9775	9775	6 be equal to an accepted bid price less the sum of:
9776	9776	7 (I) one of the following energy price indices,
9777	9777	8 selected by the bidder at the time of the bid for
9778	9778	9 the term of the contract:
9779	9779	10 (aa) the weighted-average hourly day-ahead
9780	9780	11 price for the applicable delivery year at the
9781	9781	12 busbar of all resources procured pursuant to
9782	9782	13 this subsection (d-10), weighted by actual
9783	9783	14 production from the resources; or
9784	9784	15 (bb) the projected energy price for the
9785	9785	16 PJM Interconnection, LLC Northern Illinois Hub
9786	9786	17 for the applicable delivery year determined
9787	9787	18 according to subitem (aa) of item (iii) of
9788	9788	19 subparagraph (B) of paragraph (1) of
9789	9789	20 subsection (d-5).
9790	9790	21 (II) the Base Residual Auction Capacity Price
9791	9791	22 for the ComEd zone as determined by PJM
9792	9792	23 Interconnection, LLC, divided by 24 hours per day,
9793	9793	24 for the applicable delivery year for the first 3
9794	9794	25 delivery years, and then any subsequent delivery
9795	9795	26 years unless the PJM Interconnection, LLC applies
9796	9796
9797	9797
9798	9798
9799	9799
9800	9800
9801	9801	HB3779 - 272 - LRB104 11172 AAS 21254 b
9802	9802
9803	9803
9804	9804	HB3779- 273 -LRB104 11172 AAS 21254 b HB3779 - 273 - LRB104 11172 AAS 21254 b
9805	9805	HB3779 - 273 - LRB104 11172 AAS 21254 b
9806	9806	1 the Minimum Offer Price Rule to participating
9807	9807	2 carbon-free energy resources because they supply
9808	9808	3 carbon mitigation credits pursuant to this Section
9809	9809	4 at which time, upon notice by the carbon-free
9810	9810	5 energy resource to the Commission and subject to
9811	9811	6 the Commission's confirmation, the value under
9812	9812	7 this subitem shall be zero, as further described
9813	9813	8 in the carbon mitigation credit procurement plan;
9814	9814	9 and
9815	9815	10 (III) any value of monetized federal tax
9816	9816	11 credits, direct payments, or similar subsidy
9817	9817	12 provided to the carbon-free energy resource from
9818	9818	13 any unit of government that is not already
9819	9819	14 reflected in energy prices.
9820	9820	15 If the price-per-megawatt-hour calculation
9821	9821	16 performed under item (iii) of this subparagraph (C)
9822	9822	17 for a given delivery year results in a net positive
9823	9823	18 value, then the electric utility counterparty to the
9824	9824	19 contract shall multiply such net value by the
9825	9825	20 applicable contract quantity and remit the amount to
9826	9826	21 the supplier.
9827	9827	22 To protect retail customers from retail rate
9828	9828	23 impacts that may arise upon the initiation of carbon
9829	9829	24 policy changes, if the price-per-megawatt-hour
9830	9830	25 calculation performed under item (iii) of this
9831	9831	26 subparagraph (C) for a given delivery year results in
9832	9832
9833	9833
9834	9834
9835	9835
9836	9836
9837	9837	HB3779 - 273 - LRB104 11172 AAS 21254 b
9838	9838
9839	9839
9840	9840	HB3779- 274 -LRB104 11172 AAS 21254 b HB3779 - 274 - LRB104 11172 AAS 21254 b
9841	9841	HB3779 - 274 - LRB104 11172 AAS 21254 b
9842	9842	1 a net negative value, then the supplier counterparty
9843	9843	2 to the contract shall multiply such net value by the
9844	9844	3 applicable contract quantity and remit such amount to
9845	9845	4 the electric utility counterparty. The electric
9846	9846	5 utility shall reflect such amounts remitted by
9847	9847	6 suppliers as a credit on its retail customer bills as
9848	9848	7 soon as practicable.
9849	9849	8 (iv) To ensure that retail customers in Northern
9850	9850	9 Illinois do not pay more for carbon mitigation credits
9851	9851	10 than the value such credits provide, and
9852	9852	11 notwithstanding the provisions of this subsection
9853	9853	12 (d-10), the Agency shall not accept bids for contracts
9854	9854	13 that exceed a customer protection cap equal to the
9855	9855	14 baseline costs of carbon-free energy resources.
9856	9856	15 The baseline costs for the applicable year shall
9857	9857	16 be the following:
9858	9858	17 (I) For the delivery year beginning June 1,
9859	9859	18 2022, the baseline costs shall be an amount equal
9860	9860	19 to $30.30 per megawatt-hour.
9861	9861	20 (II) For the delivery year beginning June 1,
9862	9862	21 2023, the baseline costs shall be an amount equal
9863	9863	22 to $32.50 per megawatt-hour.
9864	9864	23 (III) For the delivery year beginning June 1,
9865	9865	24 2024, the baseline costs shall be an amount equal
9866	9866	25 to $33.43 per megawatt-hour.
9867	9867	26 (IV) For the delivery year beginning June 1,
9868	9868
9869	9869
9870	9870
9871	9871
9872	9872
9873	9873	HB3779 - 274 - LRB104 11172 AAS 21254 b
9874	9874
9875	9875
9876	9876	HB3779- 275 -LRB104 11172 AAS 21254 b HB3779 - 275 - LRB104 11172 AAS 21254 b
9877	9877	HB3779 - 275 - LRB104 11172 AAS 21254 b
9878	9878	1 2025, the baseline costs shall be an amount equal
9879	9879	2 to $33.50 per megawatt-hour.
9880	9880	3 (V) For the delivery year beginning June 1,
9881	9881	4 2026, the baseline costs shall be an amount equal
9882	9882	5 to $34.50 per megawatt-hour.
9883	9883	6 An Environmental Protection Agency consultant
9884	9884	7 forecast, included in a report issued April 14, 2021,
9885	9885	8 projects that a carbon-free energy resource has the
9886	9886	9 opportunity to earn on average approximately $30.28
9887	9887	10 per megawatt-hour, for the sale of energy and capacity
9888	9888	11 during the time period between 2022 and 2027.
9889	9889	12 Therefore, the sale of carbon mitigation credits
9890	9890	13 provides the opportunity to receive an additional
9891	9891	14 amount per megawatt-hour in addition to the projected
9892	9892	15 prices for energy and capacity.
9893	9893	16 Although actual energy and capacity prices may
9894	9894	17 vary from year-to-year, the General Assembly finds
9895	9895	18 that this customer protection cap will help ensure
9896	9896	19 that the cost of carbon mitigation credits will be
9897	9897	20 less than its value, based upon the social cost of
9898	9898	21 carbon identified in the Technical Support Document
9899	9899	22 issued in February 2021 by the U.S. Interagency
9900	9900	23 Working Group on Social Cost of Greenhouse Gases and
9901	9901	24 the PJM Interconnection, LLC carbon dioxide marginal
9902	9902	25 emission rate for 2020, and that a carbon-free energy
9903	9903	26 resource receiving payment for carbon mitigation
9904	9904
9905	9905
9906	9906
9907	9907
9908	9908
9909	9909	HB3779 - 275 - LRB104 11172 AAS 21254 b
9910	9910
9911	9911
9912	9912	HB3779- 276 -LRB104 11172 AAS 21254 b HB3779 - 276 - LRB104 11172 AAS 21254 b
9913	9913	HB3779 - 276 - LRB104 11172 AAS 21254 b
9914	9914	1 credits receives no more than necessary to keep those
9915	9915	2 units in operation.
9916	9916	3 (D) No later than 7 days after the effective date of
9917	9917	4 this amendatory Act of the 102nd General Assembly, the
9918	9918	5 Agency shall publish its proposed carbon mitigation credit
9919	9919	6 procurement plan. The Plan shall provide that winning bids
9920	9920	7 shall be selected by taking into consideration which
9921	9921	8 resources best match public interest criteria that
9922	9922	9 include, but are not limited to, minimizing carbon dioxide
9923	9923	10 emissions that result from electricity consumed in
9924	9924	11 Illinois and minimizing sulfur dioxide, nitrogen oxide,
9925	9925	12 and particulate matter emissions that adversely affect the
9926	9926	13 citizens of this State. The selection of winning bids
9927	9927	14 shall also take into account the incremental environmental
9928	9928	15 benefits resulting from the procurement or procurements,
9929	9929	16 such as any existing environmental benefits that are
9930	9930	17 preserved by a procurement held under this subsection
9931	9931	18 (d-10) and would cease to exist if the procurement were
9932	9932	19 not held, including the preservation of carbon-free energy
9933	9933	20 resources. For those bidders having the same public
9934	9934	21 interest criteria score, the relative ranking of such
9935	9935	22 bidders shall be determined by price. The Plan shall
9936	9936	23 describe in detail how each public interest factor shall
9937	9937	24 be considered and weighted in the bid selection process to
9938	9938	25 ensure that the public interest criteria are applied to
9939	9939	26 the procurement. The Plan shall, to the extent practical
9940	9940
9941	9941
9942	9942
9943	9943
9944	9944
9945	9945	HB3779 - 276 - LRB104 11172 AAS 21254 b
9946	9946
9947	9947
9948	9948	HB3779- 277 -LRB104 11172 AAS 21254 b HB3779 - 277 - LRB104 11172 AAS 21254 b
9949	9949	HB3779 - 277 - LRB104 11172 AAS 21254 b
9950	9950	1 and permissible by federal law, ensure that successful
9951	9951	2 bidders make commercially reasonable efforts to apply for
9952	9952	3 federal tax credits, direct payments, or similar subsidy
9953	9953	4 programs that support carbon-free generation and for which
9954	9954	5 the successful bidder is eligible. Upon publishing of the
9955	9955	6 carbon mitigation credit procurement plan, copies of the
9956	9956	7 plan shall be posted and made publicly available on the
9957	9957	8 Agency's website. All interested parties shall have 7 days
9958	9958	9 following the date of posting to provide comment to the
9959	9959	10 Agency on the plan. All comments shall be posted to the
9960	9960	11 Agency's website. Following the end of the comment period,
9961	9961	12 but no more than 19 days later than the effective date of
9962	9962	13 this amendatory Act of the 102nd General Assembly, the
9963	9963	14 Agency shall revise the plan as necessary based on the
9964	9964	15 comments received and file its carbon mitigation credit
9965	9965	16 procurement plan with the Commission.
9966	9966	17 (E) If the Commission determines that the plan is
9967	9967	18 likely to result in the procurement of cost-effective
9968	9968	19 carbon mitigation credits, then the Commission shall,
9969	9969	20 after notice and hearing and opportunity for comment, but
9970	9970	21 no later than 42 days after the Agency filed the plan,
9971	9971	22 approve the plan or approve it with modification. For
9972	9972	23 purposes of this subsection (d-10), "cost-effective" means
9973	9973	24 carbon mitigation credits that are procured from
9974	9974	25 carbon-free energy resources at prices that are within the
9975	9975	26 limits specified in this paragraph (3). As part of the
9976	9976
9977	9977
9978	9978
9979	9979
9980	9980
9981	9981	HB3779 - 277 - LRB104 11172 AAS 21254 b
9982	9982
9983	9983
9984	9984	HB3779- 278 -LRB104 11172 AAS 21254 b HB3779 - 278 - LRB104 11172 AAS 21254 b
9985	9985	HB3779 - 278 - LRB104 11172 AAS 21254 b
9986	9986	1 Commission's review and acceptance or rejection of the
9987	9987	2 procurement results, the Commission shall, in its public
9988	9988	3 notice of successful bidders:
9989	9989	4 (i) identify how the selected carbon-free energy
9990	9990	5 resources satisfy the public interest criteria
9991	9991	6 described in this paragraph (3) of minimizing carbon
9992	9992	7 dioxide emissions that result from electricity
9993	9993	8 consumed in Illinois and minimizing sulfur dioxide,
9994	9994	9 nitrogen oxide, and particulate matter emissions that
9995	9995	10 adversely affect the citizens of this State;
9996	9996	11 (ii) specifically address how the selection of
9997	9997	12 carbon-free energy resources takes into account the
9998	9998	13 incremental environmental benefits resulting from the
9999	9999	14 procurement, including any existing environmental
10000	10000	15 benefits that are preserved by the procurements held
10001	10001	16 under this amendatory Act of the 102nd General
10002	10002	17 Assembly and would have ceased to exist if the
10003	10003	18 procurements had not been held, such as the
10004	10004	19 preservation of carbon-free energy resources;
10005	10005	20 (iii) quantify the environmental benefit of
10006	10006	21 preserving the carbon-free energy resources procured
10007	10007	22 pursuant to this subsection (d-10), including the
10008	10008	23 following:
10009	10009	24 (I) an assessment value of avoided greenhouse
10010	10010	25 gas emissions measured as the product of the
10011	10011	26 carbon-free energy resources' output over the
10012	10012
10013	10013
10014	10014
10015	10015
10016	10016
10017	10017	HB3779 - 278 - LRB104 11172 AAS 21254 b
10018	10018
10019	10019
10020	10020	HB3779- 279 -LRB104 11172 AAS 21254 b HB3779 - 279 - LRB104 11172 AAS 21254 b
10021	10021	HB3779 - 279 - LRB104 11172 AAS 21254 b
10022	10022	1 contract term, using generally accepted
10023	10023	2 methodologies for the valuation of avoided
10024	10024	3 emissions; and
10025	10025	4 (II) an assessment of costs of replacement
10026	10026	5 with other carbon-free energy resources and
10027	10027	6 renewable energy resources, including wind and
10028	10028	7 photovoltaic generation, based upon an assessment
10029	10029	8 of the prices paid for renewable energy credits
10030	10030	9 through programs and procurements conducted
10031	10031	10 pursuant to subsection (c) of Section 1-75 of this
10032	10032	11 Act, and the additional storage necessary to
10033	10033	12 produce the same or similar capability of matching
10034	10034	13 customer usage patterns.
10035	10035	14 (F) The procurements described in this paragraph (3),
10036	10036	15 including, but not limited to, the execution of all
10037	10037	16 contracts procured, shall be completed no later than
10038	10038	17 December 3, 2021. The procurement and plan approval
10039	10039	18 processes required by this paragraph (3) shall be
10040	10040	19 conducted in conjunction with the procurement and plan
10041	10041	20 approval processes required by Section 16-111.5 of the
10042	10042	21 Public Utilities Act, to the extent practicable. However,
10043	10043	22 the Agency and Commission may, as appropriate, modify the
10044	10044	23 various dates and timelines under this subparagraph and
10045	10045	24 subparagraphs (D) and (E) of this paragraph (3) to meet
10046	10046	25 the December 3, 2021 contract execution deadline.
10047	10047	26 Following the completion of such procurements, and
10048	10048
10049	10049
10050	10050
10051	10051
10052	10052
10053	10053	HB3779 - 279 - LRB104 11172 AAS 21254 b
10054	10054
10055	10055
10056	10056	HB3779- 280 -LRB104 11172 AAS 21254 b HB3779 - 280 - LRB104 11172 AAS 21254 b
10057	10057	HB3779 - 280 - LRB104 11172 AAS 21254 b
10058	10058	1 consistent with this paragraph (3), the Agency shall
10059	10059	2 calculate the payments to be made under each contract in a
10060	10060	3 timely fashion.
10061	10061	4 (F-1) Costs incurred by the electric utility pursuant
10062	10062	5 to a contract authorized by this subsection (d-10) shall
10063	10063	6 be deemed prudently incurred and reasonable in amount, and
10064	10064	7 the electric utility shall be entitled to full cost
10065	10065	8 recovery pursuant to a tariff or tariffs filed with the
10066	10066	9 Commission.
10067	10067	10 (G) The counterparty electric utility shall retire all
10068	10068	11 carbon mitigation credits used to comply with the
10069	10069	12 requirements of this subsection (d-10).
10070	10070	13 (H) If a carbon-free energy resource is sold to
10071	10071	14 another owner, the rights, obligations, and commitments
10072	10072	15 under this subsection (d-10) shall continue to the
10073	10073	16 subsequent owner.
10074	10074	17 (I) This subsection (d-10) shall become inoperative on
10075	10075	18 January 1, 2028.
10076	10076	19 (e) The draft procurement plans are subject to public
10077	10077	20 comment, as required by Section 16-111.5 of the Public
10078	10078	21 Utilities Act.
10079	10079	22 (f) The Agency shall submit the final procurement plan to
10080	10080	23 the Commission. The Agency shall revise a procurement plan if
10081	10081	24 the Commission determines that it does not meet the standards
10082	10082	25 set forth in Section 16-111.5 of the Public Utilities Act.
10083	10083	26 (g) The Agency shall assess fees to each affected utility
10084	10084
10085	10085
10086	10086
10087	10087
10088	10088
10089	10089	HB3779 - 280 - LRB104 11172 AAS 21254 b
10090	10090
10091	10091
10092	10092	HB3779- 281 -LRB104 11172 AAS 21254 b HB3779 - 281 - LRB104 11172 AAS 21254 b
10093	10093	HB3779 - 281 - LRB104 11172 AAS 21254 b
10094	10094	1 to recover the costs incurred in preparation of the annual
10095	10095	2 procurement plan for the utility.
10096	10096	3 (h) The Agency shall assess fees to each bidder to recover
10097	10097	4 the costs incurred in connection with a competitive
10098	10098	5 procurement process.
10099	10099	6 (i) A renewable energy credit, carbon emission credit,
10100	10100	7 zero emission credit, or carbon mitigation credit can only be
10101	10101	8 used once to comply with a single portfolio or other standard
10102	10102	9 as set forth in subsection (c), subsection (d), or subsection
10103	10103	10 (d-5) of this Section, respectively. A renewable energy
10104	10104	11 credit, carbon emission credit, zero emission credit, or
10105	10105	12 carbon mitigation credit cannot be used to satisfy the
10106	10106	13 requirements of more than one standard. If more than one type
10107	10107	14 of credit is issued for the same megawatt hour of energy, only
10108	10108	15 one credit can be used to satisfy the requirements of a single
10109	10109	16 standard. After such use, the credit must be retired together
10110	10110	17 with any other credits issued for the same megawatt hour of
10111	10111	18 energy.
10112	10112	19 (Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24;
10113	10113	20 103-580, eff. 12-8-23.)
10114	10114	21 (20 ILCS 3855/1-79 new)
10115	10115	22 Sec. 1-79. Planning and Procurement Bureau modeling.
10116	10116	23 Planning and Procurement Bureau shall establish an Office of
10117	10117	24 Energy Modeling that shall have the following duties and
10118	10118	25 responsibilities:
10119	10119
10120	10120
10121	10121
10122	10122
10123	10123
10124	10124	HB3779 - 281 - LRB104 11172 AAS 21254 b
10125	10125
10126	10126
10127	10127	HB3779- 282 -LRB104 11172 AAS 21254 b HB3779 - 282 - LRB104 11172 AAS 21254 b
10128	10128	HB3779 - 282 - LRB104 11172 AAS 21254 b
10129	10129	1 (a) The Office of Energy Modeling shall develop resource
10130	10130	2 adequacy analysis, impacts analysis, scenario planning,
10131	10131	3 sensitivity analysis, and program analysis pursuant to the
10132	10132	4 requirements of subsection (o) of Section 9.15 of the
10133	10133	5 Environmental Protection Act.
10134	10134	6 (b) The Office of Energy Modeling shall develop and
10135	10135	7 maintain a database of Illinois' electric generation,
10136	10136	8 transmission, distribution, and supporting infrastructure
10137	10137	9 using data from sources, including, but not limited to:
10138	10138	10 (1) the Federal Energy Regulatory Commission, the
10139	10139	11 United States Energy Information Administration, the
10140	10140	12 United States Department of Energy, and the United States
10141	10141	13 Environmental Protection Agency, or other similar sources;
10142	10142	14 (2) Illinois State agencies, including the Illinois
10143	10143	15 Power Agency, the Illinois Commerce Commission, the
10144	10144	16 Department of Commerce and Economic Opportunity, and the
10145	10145	17 Illinois Environmental Protection Agency;
10146	10146	18 (3) Regional Transmission Organizations, Independent
10147	10147	19 System Operators, or any other entity authorized by the
10148	10148	20 Federal Energy Regulatory Commission to promote the
10149	10149	21 reliability and adequacy of bulk power transmission;
10150	10150	22 (4) electric utilities, municipal utilities, and
10151	10151	23 electric cooperatives; and
10152	10152	24 (5) other public and private data sources as
10153	10153	25 necessary.
10154	10154	26 The database shall be published and maintained online in
10155	10155
10156	10156
10157	10157
10158	10158
10159	10159
10160	10160	HB3779 - 282 - LRB104 11172 AAS 21254 b
10161	10161
10162	10162
10163	10163	HB3779- 283 -LRB104 11172 AAS 21254 b HB3779 - 283 - LRB104 11172 AAS 21254 b
10164	10164	HB3779 - 283 - LRB104 11172 AAS 21254 b
10165	10165	1 machine-readable formats in regular, distinct, numbered
10166	10166	2 versions. To the extent that sensitive datasets cannot be made
10167	10167	3 public because they contain information meeting the Federal
10168	10168	4 Energy Regulatory Commission's definition of either "critical
10169	10169	5 electric infrastructure information" or "critical energy
10170	10170	6 infrastructure information" under 18 CFR 388.113, meeting the
10171	10171	7 definition of "trade secret" under Section 2 of the Illinois
10172	10172	8 Trade Secrets Act, or otherwise containing confidential or
10173	10173	9 sensitive materials, the Office of Energy Modeling shall both
10174	10174	10 publish simulated datasets designed to maintain the
10175	10175	11 statistical patterns and relationships present in the original
10176	10176	12 dataset and allow secure and confidential access to the
10177	10177	13 sensitive data for qualified entities, such as utilities,
10178	10178	14 academics, or advocates under confidentiality agreements and
10179	10179	15 to the extent permitted by law.
10180	10180	16 (c) The Office of Energy Modeling shall perform energy
10181	10181	17 modeling studies and develop or supervise development of
10182	10182	18 production cost, capacity expansion, and resource adequacy
10183	10183	19 models for Illinois. The Agency shall develop models using
10184	10184	20 open source energy modeling tools and open data. This
10185	10185	21 development will occur in public, using a web-based interface
10186	10186	22 to open source version control software, and the models will
10187	10187	23 be published with permissive open-source licenses. The Office
10188	10188	24 of Energy Modeling shall establish a transparent modeling
10189	10189	25 process that accepts and considers public comment. All studies
10190	10190	26 funded, commissioned, or undertaken by the Office of Energy
10191	10191
10192	10192
10193	10193
10194	10194
10195	10195
10196	10196	HB3779 - 283 - LRB104 11172 AAS 21254 b
10197	10197
10198	10198
10199	10199	HB3779- 284 -LRB104 11172 AAS 21254 b HB3779 - 284 - LRB104 11172 AAS 21254 b
10200	10200	HB3779 - 284 - LRB104 11172 AAS 21254 b
10201	10201	1 Modeling shall publish the inputs, assumptions, parameters,
10202	10202	2 constraints, and forecasts associated with the study, in
10203	10203	3 machine-readable file formats compatible with the software
10204	10204	4 used to produce the study, such that the Office of Energy
10205	10205	5 Modeling or another stakeholder could recreate the study
10206	10206	6 results using the same modeling software, regardless of
10207	10207	7 whether that software is open source or proprietary.
10208	10208	8 (d) The Office of Energy Modeling shall conduct reviews of
10209	10209	9 external energy system reports, modeling, and studies of
10210	10210	10 Illinois-specific and regional resource adequacy produced by
10211	10211	11 regional transmission organizations, reliability
10212	10212	12 organizations, and the federal government and shall produce
10213	10213	13 executive summaries and analyses of the key findings, methods,
10214	10214	14 and implications of the reports and studies. The Office of
10215	10215	15 Energy Modeling shall also, from time to time and within
10216	10216	16 reason, be available to provide insights on energy system
10217	10217	17 modeling and analysis to the Governor, members of the General
10218	10218	18 Assembly, other state agencies, units of local government, and
10219	10219	19 the public.
10220	10220	20 (e) The Office of Energy Modeling may obtain outside
10221	10221	21 resources, including, but not limited to, consultants or other
10222	10222	22 external entities, to assist in the performance of its duties.
10223	10223	23 Any work performed using outside resources, including work by
10224	10224	24 consultants or other external entities, must be conducted
10225	10225	25 openly and transparently using open-source tools and data
10226	10226	26 whenever possible and shall contribute to the open source
10227	10227
10228	10228
10229	10229
10230	10230
10231	10231
10232	10232	HB3779 - 284 - LRB104 11172 AAS 21254 b
10233	10233
10234	10234
10235	10235	HB3779- 285 -LRB104 11172 AAS 21254 b HB3779 - 285 - LRB104 11172 AAS 21254 b
10236	10236	HB3779 - 285 - LRB104 11172 AAS 21254 b
10237	10237	1 models and datasets maintained by the Office of Energy
10238	10238	2 Modeling.
10239	10239	3 (20 ILCS 3855/1-93 new)
10240	10240	4 Sec. 1-93. Energy Storage Procurement Program.
10241	10241	5 (a) The General Assembly finds that:
10242	10242	6 (1) The health, welfare, and prosperity of all
10243	10243	7 Illinois residents require that the State of Illinois act
10244	10244	8 to reduce existing and avoid new carbon emissions from
10245	10245	9 electric generation sources while continuing to ensure
10246	10246	10 clean, affordable, and reliable electricity for all
10247	10247	11 residents.
10248	10248	12 (2) Energy storage resources are necessary for the
10249	10249	13 State's transition to 100% clean energy, to reduce
10250	10250	14 reliance on carbon-intensive energy resources, for
10251	10251	15 transitioning to a fully decarbonized electricity sector,
10252	10252	16 and to help ensure health and welfare of the State's
10253	10253	17 residents.
10254	10254	18 (3) Illinois is likely to require substantial energy
10255	10255	19 storage resources that will play a key role in allowing
10256	10256	20 the State's power grid to accommodate reduced operations
10257	10257	21 from fossil fuel power plants pursuant to emission limit
10258	10258	22 requirements scheduled to occur in 2030, 2035, and beyond,
10259	10259	23 as set forth in Section 9.15(o) of the Environmental
10260	10260	24 Protection Act.
10261	10261	25 (b) The Agency shall conduct an initial forward
10262	10262
10263	10263
10264	10264
10265	10265
10266	10266
10267	10267	HB3779 - 285 - LRB104 11172 AAS 21254 b
10268	10268
10269	10269
10270	10270	HB3779- 286 -LRB104 11172 AAS 21254 b HB3779 - 286 - LRB104 11172 AAS 21254 b
10271	10271	HB3779 - 286 - LRB104 11172 AAS 21254 b
10272	10272	1 procurement of utility-scale energy storage resources not to
10273	10273	2 exceed 1,500 megawatts. The IPA shall develop a confidential
10274	10274	3 benchmark and shall have solicited, received, and opened
10275	10275	4 sealed bids for such initial procurement not later than August
10276	10276	5 26, 2025. This initial forward procurement shall utilize the
10277	10277	6 procurement process, structure, and contract terms as
10278	10278	7 recommended in the staff of the Illinois Commerce Commission's
10279	10279	8 report submitted pursuant to Section 16-135(g) of the Public
10280	10280	9 Utilities Act.
10281	10281	10 (c) Within 270 days after the effective date of this
10282	10282	11 amendatory Act of the 104th General Assembly, the Agency shall
10283	10283	12 develop an energy storage procurement plan that shall include
10284	10284	13 procurement programs and competitive procurement events
10285	10285	14 necessary to meet the goals set forth in this Section. The
10286	10286	15 energy storage procurement plan and any subsequent revisions
10287	10287	16 shall be subject to review and approval by the Commission
10288	10288	17 under Section 16-111.5 of the Public Utilities Act. The Agency
10289	10289	18 shall endeavor to coordinate submission of the energy storage
10290	10290	19 procurement plan and any subsequent revisions simultaneous
10291	10291	20 with long-term renewable resources procurement plans pursuant
10292	10292	21 to Sections 1-56(b) and 1-75(c) of this Act and Section
10293	10293	22 16-111.5 of the Public Utilities Act.
10294	10294	23 (d) The energy storage procurement plan shall develop
10295	10295	24 procurements and programs as necessary to achieve an initial
10296	10296	25 goal of having at least 3,000 megawatts of cumulative energy
10297	10297	26 storage capacity by 2030, of sufficient duration to qualify as
10298	10298
10299	10299
10300	10300
10301	10301
10302	10302
10303	10303	HB3779 - 286 - LRB104 11172 AAS 21254 b
10304	10304
10305	10305
10306	10306	HB3779- 287 -LRB104 11172 AAS 21254 b HB3779 - 287 - LRB104 11172 AAS 21254 b
10307	10307	HB3779 - 287 - LRB104 11172 AAS 21254 b
10308	10308	1 a capacity resource, interconnected to or able to participate
10309	10309	2 in markets run by the Midcontinent Independent System
10310	10310	3 Operator, Inc., PJM Interconnection, LLC, or their respective
10311	10311	4 successors. The Agency may establish additional targets for
10312	10312	5 such capacity based on identified resource adequacy needs for
10313	10313	6 Midcontinent Independent System Operator, Inc., PJM
10314	10314	7 Interconnection, LLC, or their respective successors. The
10315	10315	8 Agency shall regularly assess, both prior to and after 2030,
10316	10316	9 whether procurement of additional amounts of energy storage
10317	10317	10 capacity is necessary to support achievement of the goals set
10318	10318	11 forth in Public Act 102-662 and shall include such proposals
10319	10319	12 in revisions to the energy storage procurement plan pursuant
10320	10320	13 to subsection (f) of this Section.
10321	10321	14 (e) The energy storage procurement plan shall take into
10322	10322	15 consideration the following:
10323	10323	16 (1) requirements for interconnection milestones
10324	10324	17 sufficient to meet operational date targets including the
10325	10325	18 evaluation of projects proposed to augment or replace
10326	10326	19 existing resources at existing interconnection sites;
10327	10327	20 (2) requirements for demonstrated experience in
10328	10328	21 bringing utility-scale energy storage facilities to
10329	10329	22 commercial readiness, aggregating behind-the-meter demand
10330	10330	23 and storage resources, or equivalent expertise;
10331	10331	24 (3) requirements for demonstration of binding site
10332	10332	25 control sufficient for proposed energy storage facilities;
10333	10333	26 (4) the development of contract, payment, and
10334	10334
10335	10335
10336	10336
10337	10337
10338	10338
10339	10339	HB3779 - 287 - LRB104 11172 AAS 21254 b
10340	10340
10341	10341
10342	10342	HB3779- 288 -LRB104 11172 AAS 21254 b HB3779 - 288 - LRB104 11172 AAS 21254 b
10343	10343	HB3779 - 288 - LRB104 11172 AAS 21254 b
10344	10344	1 performance structures that enable project development and
10345	10345	2 finance;
10346	10346	3 (5) the need to protect retail customers from retail
10347	10347	4 rate impacts that may arise, including through the
10348	10348	5 reduction of the price paid under a contract, or
10349	10349	6 remittance by suppliers back to utilities, for a given
10350	10350	7 delivery year based on energy price and capacity price
10351	10351	8 indices;
10352	10352	9 (6) provisions for adjustments to contracts in the
10353	10353	10 event of unanticipated circumstances;
10354	10354	11 (7) operational requirements for energy storage
10355	10355	12 services contracted; and
10356	10356	13 (8) commitments of the energy storage systems to serve
10357	10357	14 Illinois resource adequacy needs, consistent with Illinois
10358	10358	15 critical resource adequacy needs as identified in the
10359	10359	16 resource adequacy study and resource planning process
10360	10360	17 described in subsection (o) of Section 9.15 of the
10361	10361	18 Environmental Protection Act, as well as any relevant
10362	10362	19 modeling performed by the Agency or related available
10363	10363	20 recommendations or findings of the North American Electric
10364	10364	21 Reliability Corporation, PJM Interconnection, LLC, and
10365	10365	22 Midcontinent Independent System Operator, Inc., or their
10366	10366	23 respective successors.
10367	10367	24 (f) The Agency shall review, and may revise on an
10368	10368	25 expedited basis, the energy storage procurement plan at least
10369	10369	26 every 2 years. Revisions to the energy storage procurement
10370	10370
10371	10371
10372	10372
10373	10373
10374	10374
10375	10375	HB3779 - 288 - LRB104 11172 AAS 21254 b
10376	10376
10377	10377
10378	10378	HB3779- 289 -LRB104 11172 AAS 21254 b HB3779 - 289 - LRB104 11172 AAS 21254 b
10379	10379	HB3779 - 289 - LRB104 11172 AAS 21254 b
10380	10380	1 plan may address the following:
10381	10381	2 (1) updates to procurement targets as approved by the
10382	10382	3 Commission under the resource adequacy study and resource
10383	10383	4 planning process described in subsection (o) of Section
10384	10384	5 9.15 of the Environmental Protection Act or as otherwise
10385	10385	6 may be approved by the Commission in a revised energy
10386	10386	7 storage procurement plan;
10387	10387	8 (2) revisions to contract, payment, and performance
10388	10388	9 structures to ensure development, protect retail customers
10389	10389	10 from retail rate impacts, and address market and
10390	10390	11 technology changes insofar as the revisions do not affect
10391	10391	12 existing and active contracts; and
10392	10392	13 (3) other plan components as developed by the Agency.
10393	10393	14 (g) All procurements under this Section shall comply with
10394	10394	15 the geographic requirements in subparagraph (I) of paragraph
10395	10395	16 (1) of subsection (c) of Section 1-75, shall support energy
10396	10396	17 storage systems interconnected to the ComEd Zone of PJM
10397	10397	18 Interconnection, LLC, or Zone 4 of Midcontinent Independent
10398	10398	19 System Operator, Inc., or their respective successors, and
10399	10399	20 shall follow the procurement processes and procedures
10400	10400	21 described in this Section and Section 16-111.5 of the Public
10401	10401	22 Utilities Act.
10402	10402	23 (h) The Agency shall procure energy storage resources that
10403	10403	24 are cost-effective. The procurement administrator shall
10404	10404	25 establish confidential price benchmarks based on publicly
10405	10405	26 available data on regional technology and construction costs.
10406	10406
10407	10407
10408	10408
10409	10409
10410	10410
10411	10411	HB3779 - 289 - LRB104 11172 AAS 21254 b
10412	10412
10413	10413
10414	10414	HB3779- 290 -LRB104 11172 AAS 21254 b HB3779 - 290 - LRB104 11172 AAS 21254 b
10415	10415	HB3779 - 290 - LRB104 11172 AAS 21254 b
10416	10416	1 Benchmarks shall reflect development, financing, and related
10417	10417	2 costs resulting from requirements imposed through the energy
10418	10418	3 storage procurement plan and other provisions of State law. As
10419	10419	4 used in this subsection, "cost-effective" means that the
10420	10420	5 energy storage resources procurement price, plus any projected
10421	10421	6 market revenue, does not exceed confidential benchmarks.
10422	10422	7 (i) Energy storage resources procured under this Section
10423	10423	8 must be from energy storage systems built by general
10424	10424	9 contractors that enter into a project labor agreement prior to
10425	10425	10 construction. The project labor agreement shall be filed with
10426	10426	11 the Agency in accordance with procedures established by the
10427	10427	12 Agency through its energy storage procurement plan. Any
10428	10428	13 information submitted to the Agency under this subsection
10429	10429	14 shall be considered commercially sensitive information. At a
10430	10430	15 minimum, the project labor agreement must provide the names,
10431	10431	16 addresses, and occupations of the owner of the plant and the
10432	10432	17 individuals representing the labor organization employees
10433	10433	18 participating in the project labor agreement in accordance
10434	10434	19 with the Project Labor Agreements Act. The agreement must also
10435	10435	20 specify the terms and conditions as described in this Act.
10436	10436	21 Each energy storage system shall be subject to the prevailing
10437	10437	22 wage requirements included in the Prevailing Wage Act. The
10438	10438	23 Agency shall require verification that all construction
10439	10439	24 performed on the energy storage system by the energy storage
10440	10440	25 resources delivery contract holder, its contractors, or its
10441	10441	26 subcontractors relating to construction of the energy storage
10442	10442
10443	10443
10444	10444
10445	10445
10446	10446
10447	10447	HB3779 - 290 - LRB104 11172 AAS 21254 b
10448	10448
10449	10449
10450	10450	HB3779- 291 -LRB104 11172 AAS 21254 b HB3779 - 291 - LRB104 11172 AAS 21254 b
10451	10451	HB3779 - 291 - LRB104 11172 AAS 21254 b
10452	10452	1 system is performed by construction employees receiving an
10453	10453	2 amount for that work that is equal to or greater than the
10454	10454	3 general prevailing rate, as that term is used in Section 3 of
10455	10455	4 the Prevailing Wage Act.
10456	10456	5 (j) In order to advance priority access to the clean
10457	10457	6 energy economy for businesses and workers from communities
10458	10458	7 that have been excluded from economic opportunities in the
10459	10459	8 energy sector, have been subject to disproportionate levels of
10460	10460	9 pollution, and have disproportionately experienced negative
10461	10461	10 public health outcomes, the Agency shall update its Equity
10462	10462	11 Accountability System and minimum equity standards established
10463	10463	12 under subsections (c-10), (c-15), (c-20), (c-25), and (c-30)
10464	10464	13 of Section 1-75 of this Act to include energy storage
10465	10465	14 resources procurements and programs, and include such
10466	10466	15 modifications in its energy storage procurement plan
10467	10467	16 submission to the Commission under Section 16-111.5 of the
10468	10468	17 Public Utilities Act.
10469	10469	18 (k) In order to promote the competitive development of
10470	10470	19 energy storage systems in furtherance of the State's interest
10471	10471	20 in the health, safety, and welfare of its residents, energy
10472	10472	21 storage resources shall not be eligible to be selected under
10473	10473	22 this Section if sourced from an energy storage system whose
10474	10474	23 costs were being recovered through rates regulated by this
10475	10475	24 State or any other state or states on or after January 1, 2017.
10476	10476	25 Each contract executed to purchase energy storage resources
10477	10477	26 under this Section shall provide for the contract's
10478	10478
10479	10479
10480	10480
10481	10481
10482	10482
10483	10483	HB3779 - 291 - LRB104 11172 AAS 21254 b
10484	10484
10485	10485
10486	10486	HB3779- 292 -LRB104 11172 AAS 21254 b HB3779 - 292 - LRB104 11172 AAS 21254 b
10487	10487	HB3779 - 292 - LRB104 11172 AAS 21254 b
10488	10488	1 termination if the costs of the energy storage system
10489	10489	2 supplying the energy storage resources subsequently begin to
10490	10490	3 be recovered through rates regulated by this State or any
10491	10491	4 other state or states. Each contract shall provide that, in
10492	10492	5 the event the costs of the energy storage system supplying the
10493	10493	6 energy storage resources subsequently begin to be recovered
10494	10494	7 through rates regulated by this State or any other state or
10495	10495	8 states, the supplier of the energy storage resources must
10496	10496	9 return 110% of all payments received under the energy storage
10497	10497	10 resources procurement contract. Amounts returned under the
10498	10498	11 requirements of this subsection shall be refunded to the
10499	10499	12 respective ratepayers in the same proportion as the cost
10500	10500	13 allocation for the contract. No entity shall be permitted to
10501	10501	14 bid unless it certifies to the Agency that it is not an
10502	10502	15 electric utility, as defined in Section 16-102 of the Public
10503	10503	16 Utilities Act, serving more than 10,000 customers in the
10504	10504	17 State.
10505	10505	18 (l) The Agency shall require, as a prerequisite to payment
10506	10506	19 for any energy storage resources procurement, that the winning
10507	10507	20 bidder provide the Agency or its designee a copy of the
10508	10508	21 interconnection agreement under which the applicable energy
10509	10509	22 storage system is connected to the transmission or
10510	10510	23 distribution system as required in this Section.
10511	10511	24 Section 105. The Counties Code is amended by adding
10512	10512	25 Division 5-46 as follows:
10513	10513
10514	10514
10515	10515
10516	10516
10517	10517
10518	10518	HB3779 - 292 - LRB104 11172 AAS 21254 b
10519	10519
10520	10520
10521	10521	HB3779- 293 -LRB104 11172 AAS 21254 b HB3779 - 293 - LRB104 11172 AAS 21254 b
10522	10522	HB3779 - 293 - LRB104 11172 AAS 21254 b
10523	10523	1 (55 ILCS 5/Div. 5-46 heading new)
10524	10524	2 Division 5-46 Solar Bill of Rights
10525	10525	3 (55 ILCS 5/5-46005 new)
10526	10526	4 Sec. 5-46005. Definitions. As used in this Division:
10527	10527	5 "Low voltage solar powered device" means a piece of
10528	10528	6 equipment designed for a particular purpose, including, but
10529	10529	7 not limited to, doorbells, security systems and illumination
10530	10530	8 equipment, powered by a solar collector operating at less than
10531	10531	9 50 volts and located:
10532	10532	10 (1) entirely within the lot or parcel owned by the
10533	10533	11 property owner; or
10534	10534	12 (2) within a common area without being permanently
10535	10535	13 attached to common property.
10536	10536	14 "Solar energy " means radiant energy received from the sun
10537	10537	15 at wave lengths suitable for heat transfer, photosynthetic
10538	10538	16 use, or photovoltaic use.
10539	10539	17 "Solar collector" means:
10540	10540	18 (1) an assembly, structure, or design, including
10541	10541	19 passive elements, used for gathering, concentrating, or
10542	10542	20 absorbing direct and indirect solar energy, specially
10543	10543	21 designed for holding a substantial amount of useful
10544	10544	22 thermal energy and to transfer that energy to a gas,
10545	10545	23 solid, or liquid or to use that energy directly; or
10546	10546	24 (2) a mechanism that absorbs solar energy and converts
10547	10547
10548	10548
10549	10549
10550	10550
10551	10551
10552	10552	HB3779 - 293 - LRB104 11172 AAS 21254 b
10553	10553
10554	10554
10555	10555	HB3779- 294 -LRB104 11172 AAS 21254 b HB3779 - 294 - LRB104 11172 AAS 21254 b
10556	10556	HB3779 - 294 - LRB104 11172 AAS 21254 b
10557	10557	1 it into electricity; or
10558	10558	2 (3) a mechanism or process used for gathering solar
10559	10559	3 energy through wind or thermal gradients; or
10560	10560	4 (4) a component used to transfer thermal energy to a
10561	10561	5 gas, solid, or liquid, or to convert it into electricity.
10562	10562	6 "Solar storage mechanism" means equipment or elements
10563	10563	7 (such as piping and transfer mechanisms, containers, heat
10564	10564	8 exchangers, batteries, or controls thereof, and gases, solids,
10565	10565	9 liquids, or combinations thereof) that are utilized for
10566	10566	10 storing solar energy, gathered by a solar collector, for
10567	10567	11 subsequent use.
10568	10568	12 "Solar energy system" means:
10569	10569	13 (1) a complete assembly, structure, or design of solar
10570	10570	14 collector or a solar storage mechanism that uses solar
10571	10571	15 energy for generating electricity or for heating or
10572	10572	16 cooling gases, solids, liquids, or other materials; and
10573	10573	17 (2) the design, materials, or elements of a system and
10574	10574	18 its maintenance, operation, and labor components, and the
10575	10575	19 necessary components, if any, of supplemental conventional
10576	10576	20 energy systems designed or constructed to interface with a
10577	10577	21 solar energy system.
10578	10578	22 (55 ILCS 5/5-46010 new)
10579	10579	23 Sec. 5-46010. Prohibitions. Notwithstanding any provision
10580	10580	24 of this Code or other provision of law, the adoption of any
10581	10581	25 ordinance or resolution, or exercise of any power, by a county
10582	10582
10583	10583
10584	10584
10585	10585
10586	10586
10587	10587	HB3779 - 294 - LRB104 11172 AAS 21254 b
10588	10588
10589	10589
10590	10590	HB3779- 295 -LRB104 11172 AAS 21254 b HB3779 - 295 - LRB104 11172 AAS 21254 b
10591	10591	HB3779 - 295 - LRB104 11172 AAS 21254 b
10592	10592	1 which prohibits or has the effect of prohibiting the
10593	10593	2 installation of a solar energy system or low voltage solar
10594	10594	3 powered device is expressly prohibited.
10595	10595	4 (55 ILCS 5/5-46015 new)
10596	10596	5 Sec. 5-46015. Home rule. A home rule unit may not regulate
10597	10597	6 the Solar Bill of Rights in a manner more restrictive than the
10598	10598	7 regulation by the State under this Division. This Section is a
10599	10599	8 limitation under subsection (i) of Section 6 of Article VII of
10600	10600	9 the Illinois Constitution on the concurrent exercise by home
10601	10601	10 rule units of powers and functions exercised by the State.
10602	10602	11 (55 ILCS 5/5-46020 new)
10603	10603	12 Sec. 5-46020. Costs; attorney 's fees. In any litigation
10604	10604	13 arising under this Division or involving the application of
10605	10605	14 this Division, the prevailing party shall be entitled to costs
10606	10606	15 and reasonable attorney's fees.
10607	10607	16 (55 ILCS 5/5-46025 new)
10608	10608	17 Sec. 5-46025. Inapplicability; applicability.
10609	10609	18 (a) This Division shall not apply to any building that:
10610	10610	19 (1) is greater than 60 feet in height; or
10611	10611	20 (2) has a shared roof and is subject to a homeowners'
10612	10612	21 association, common interest community association, or
10613	10613	22 condominium unit owners' association.
10614	10614	23 (b) Notwithstanding subsection (a) of this Section, this
10615	10615
10616	10616
10617	10617
10618	10618
10619	10619
10620	10620	HB3779 - 295 - LRB104 11172 AAS 21254 b
10621	10621
10622	10622
10623	10623	HB3779- 296 -LRB104 11172 AAS 21254 b HB3779 - 296 - LRB104 11172 AAS 21254 b
10624	10624	HB3779 - 296 - LRB104 11172 AAS 21254 b
10625	10625	1 Division shall apply to any building with a shared roof:
10626	10626	2 (1) where the solar energy system is located entirely
10627	10627	3 within that portion of the shared roof owned and
10628	10628	4 maintained by the property owner;
10629	10629	5 (2) where all property owners sharing the shared roof
10630	10630	6 are in agreement to install a solar energy system; or
10631	10631	7 (3) to the extent this Division applies to low voltage
10632	10632	8 solar powered devices.
10633	10633	9 (c) As used in this Section, "shared roof" means any roof
10634	10634	10 that (i) serves more than one unit, including, but not limited
10635	10635	11 to, a contiguous roof serving adjacent units, or (ii) is part
10636	10636	12 of the common elements or common area.
10637	10637	13 Section 110. The Illinois Municipal Code is amended by
10638	10638	14 changing Sections 11-119.1-4 and 11-119.1-10 and by adding
10639	10639	15 Division 15.5 to Article 11 as follows:
10640	10640	16 (65 ILCS 5/Art. 11 Div. 15.5 heading new)
10641	10641	17 DIVISION. 15.5. SOLAR BILL OF RIGHTS
10642	10642	18 (65 ILCS 5/11-15.5-5 new)
10643	10643	19 Sec. 11-15.5-5. Definitions. As used in this Division:
10644	10644	20 "Low voltage solar powered device" means a piece of
10645	10645	21 equipment designed for a particular purpose, including, but
10646	10646	22 not limited to, doorbells, security systems and illumination
10647	10647	23 equipment, powered by a solar collector operating at less than
10648	10648
10649	10649
10650	10650
10651	10651
10652	10652
10653	10653	HB3779 - 296 - LRB104 11172 AAS 21254 b
10654	10654
10655	10655
10656	10656	HB3779- 297 -LRB104 11172 AAS 21254 b HB3779 - 297 - LRB104 11172 AAS 21254 b
10657	10657	HB3779 - 297 - LRB104 11172 AAS 21254 b
10658	10658	1 50 volts and located:
10659	10659	2 (1) entirely within the lot or parcel owned by the
10660	10660	3 property owner; or
10661	10661	4 (2) within a common area without being permanently
10662	10662	5 attached to common property.
10663	10663	6 "Solar energy" means radiant energy received from the sun
10664	10664	7 at wave lengths suitable for heat transfer, photosynthetic
10665	10665	8 use, or photovoltaic use.
10666	10666	9 "Solar collector" means:
10667	10667	10 (1) an assembly, structure, or design, including
10668	10668	11 passive elements, used for gathering, concentrating, or
10669	10669	12 absorbing direct and indirect solar energy, specially
10670	10670	13 designed for holding a substantial amount of useful
10671	10671	14 thermal energy and to transfer that energy to a gas,
10672	10672	15 solid, or liquid or to use that energy directly; or
10673	10673	16 (2) a mechanism that absorbs solar energy and converts
10674	10674	17 it into electricity; or
10675	10675	18 (3) a mechanism or process used for gathering solar
10676	10676	19 energy through wind or thermal gradients; or
10677	10677	20 (4) a component used to transfer thermal energy to a
10678	10678	21 gas, solid, or liquid, or to convert it into electricity.
10679	10679	22 "Solar storage mechanism" means equipment or elements
10680	10680	23 (such as piping and transfer mechanisms, containers, heat
10681	10681	24 exchangers, batteries, or controls thereof, and gases, solids,
10682	10682	25 liquids, or combinations thereof) that are utilized for
10683	10683	26 storing solar energy, gathered by a solar collector, for
10684	10684
10685	10685
10686	10686
10687	10687
10688	10688
10689	10689	HB3779 - 297 - LRB104 11172 AAS 21254 b
10690	10690
10691	10691
10692	10692	HB3779- 298 -LRB104 11172 AAS 21254 b HB3779 - 298 - LRB104 11172 AAS 21254 b
10693	10693	HB3779 - 298 - LRB104 11172 AAS 21254 b
10694	10694	1 subsequent use.
10695	10695	2 "Solar energy system" means:
10696	10696	3 (1) a complete assembly, structure, or design of solar
10697	10697	4 collector or a solar storage mechanism that uses solar
10698	10698	5 energy for generating electricity or for heating or
10699	10699	6 cooling gases, solids, liquids, or other materials; and
10700	10700	7 (2) the design, materials, or elements of a system and
10701	10701	8 its maintenance, operation, and labor components, and the
10702	10702	9 necessary components, if any, of supplemental conventional
10703	10703	10 energy systems designed or constructed to interface with a
10704	10704	11 solar energy system.
10705	10705	12 (65 ILCS 5/11-15.5-10 new)
10706	10706	13 Sec. 11-15.5-10. Prohibitions. Notwithstanding any
10707	10707	14 provision of this Code or other provision of law, the adoption
10708	10708	15 of any ordinance or resolution, or exercise of any power, by
10709	10709	16 municipality that prohibits or has the effect of prohibiting
10710	10710	17 the installation of a solar energy system or low voltage solar
10711	10711	18 powered device is expressly prohibited; provided however,
10712	10712	19 municipalities that own local electric distribution systems
10713	10713	20 may adopt and implement reasonable policies, not inconsistent
10714	10714	21 with Section 17-900 of the Public Utilities Act, regarding the
10715	10715	22 interconnection and use of solar energy systems.
10716	10716	23 (65 ILCS 5/11-15.5-15 new)
10717	10717	24 Sec. 11-15.5-15. Home rule. A home rule unit may not
10718	10718
10719	10719
10720	10720
10721	10721
10722	10722
10723	10723	HB3779 - 298 - LRB104 11172 AAS 21254 b
10724	10724
10725	10725
10726	10726	HB3779- 299 -LRB104 11172 AAS 21254 b HB3779 - 299 - LRB104 11172 AAS 21254 b
10727	10727	HB3779 - 299 - LRB104 11172 AAS 21254 b
10728	10728	1 regulate the Solar Bill of Rights in a manner more restrictive
10729	10729	2 than the regulation by the State under this Division. This
10730	10730	3 Section is a limitation under subsection (i) of Section 6 of
10731	10731	4 Article VII of the Illinois Constitution on the concurrent
10732	10732	5 exercise by home rule units of powers and functions exercised
10733	10733	6 by the State.
10734	10734	7 (65 ILCS 5/11-15.5-20 new)
10735	10735	8 Sec. 11-15.5-20. Costs; attorney's fees. In any litigation
10736	10736	9 arising under this Division or involving the application of
10737	10737	10 this Division, the prevailing party shall be entitled to costs
10738	10738	11 and reasonable attorney's fees.
10739	10739	12 (65 ILCS 5/11-15.25 new)
10740	10740	13 Sec. 11-15.25. Inapplicability; applicability.
10741	10741	14 (a) This Division shall not apply to any building that:
10742	10742	15 (1) is greater than 60 feet in height; or
10743	10743	16 (2) has a shared roof and is subject to a homeowners'
10744	10744	17 association, common interest community association, or
10745	10745	18 condominium unit owners' association.
10746	10746	19 (b) Notwithstanding subsection (a) of this Section, this
10747	10747	20 Division shall apply to any building with a shared roof:
10748	10748	21 (1) where the solar energy system is located entirely
10749	10749	22 within that portion of the shared roof owned and
10750	10750	23 maintained by the property owner;
10751	10751	24 (2) where all property owners sharing the shared roof
10752	10752
10753	10753
10754	10754
10755	10755
10756	10756
10757	10757	HB3779 - 299 - LRB104 11172 AAS 21254 b
10758	10758
10759	10759
10760	10760	HB3779- 300 -LRB104 11172 AAS 21254 b HB3779 - 300 - LRB104 11172 AAS 21254 b
10761	10761	HB3779 - 300 - LRB104 11172 AAS 21254 b
10762	10762	1 are in agreement to install a solar energy system; or
10763	10763	2 (3) to the extent this Division applies to low voltage
10764	10764	3 solar powered devices.
10765	10765	4 (c) As used in this Section, "shared roof" means any roof
10766	10766	5 that (i) serves more than one unit, including, but not limited
10767	10767	6 to, a contiguous roof serving adjacent units, or (ii) is part
10768	10768	7 of the common elements or common area.
10769	10769	8 (65 ILCS 5/11-119.1-4) (from Ch. 24, par. 11-119.1-4)
10770	10770	9 Sec. 11-119.1-4. Municipal Power Agencies.
10771	10771	10 A. Any 2 or more municipalities, contiguous or
10772	10772	11 noncontiguous, and which operate an electric utility system,
10773	10773	12 may form a municipal power agency by the execution of an agency
10774	10774	13 agreement authorized by an ordinance adopted by the governing
10775	10775	14 body of each municipality. The agency agreement may state:
10776	10776	15 (1) that the municipal power agency is created and
10777	10777	16 incorporated under the provisions of this Division as a
10778	10778	17 body politic and corporate, municipal corporation and unit
10779	10779	18 of local government of the State of Illinois;
10780	10780	19 (2) the name of the agency and the date of its
10781	10781	20 establishment;
10782	10782	21 (3) that names of the municipalities which have
10783	10783	22 adopted the agency agreement and constitute the initial
10784	10784	23 members of the municipal power agency;
10785	10785	24 (4) the names and addresses of the persons initially
10786	10786	25 appointed in the ordinances adopting the agency agreement
10787	10787
10788	10788
10789	10789
10790	10790
10791	10791
10792	10792	HB3779 - 300 - LRB104 11172 AAS 21254 b
10793	10793
10794	10794
10795	10795	HB3779- 301 -LRB104 11172 AAS 21254 b HB3779 - 301 - LRB104 11172 AAS 21254 b
10796	10796	HB3779 - 301 - LRB104 11172 AAS 21254 b
10797	10797	1 to serve on the Board of Directors and act as the
10798	10798	2 representatives of the municipalities, respectively, in
10799	10799	3 the exercise of their powers as members;
10800	10800	4 (5) the limitations, if any, upon the terms of office
10801	10801	5 of the directors, provided that such directors shall
10802	10802	6 always be selected and vacancies in their offices declared
10803	10803	7 and filled by ordinances adopted by the governing body of
10804	10804	8 the respective municipalities;
10805	10805	9 (6) the location by city, village or incorporated town
10806	10806	10 in the State of Illinois of the principal office of the
10807	10807	11 municipal power agency;
10808	10808	12 (7) provisions for the disposition, division or
10809	10809	13 distribution of obligations, property and assets of the
10810	10810	14 municipal power agency upon dissolution; and
10811	10811	15 (8) any other provisions for regulating the business
10812	10812	16 of the municipal power agency or the conduct of its
10813	10813	17 affairs which may be agreed to by the member
10814	10814	18 municipalities, consistent with this Division, including,
10815	10815	19 without limitation, any provisions for weighted voting
10816	10816	20 among the member municipalities or by the directors.
10817	10817	21 B. The presiding officer of the Board of Directors of any
10818	10818	22 municipal power agency established pursuant to this Division
10819	10819	23 or such other officer selected by the Board of Directors,
10820	10820	24 within 3 months after establishment, shall file a certified
10821	10821	25 copy of the agency agreement and a list of the municipalities
10822	10822	26 which have adopted the agreement with the recorder of deeds of
10823	10823
10824	10824
10825	10825
10826	10826
10827	10827
10828	10828	HB3779 - 301 - LRB104 11172 AAS 21254 b
10829	10829
10830	10830
10831	10831	HB3779- 302 -LRB104 11172 AAS 21254 b HB3779 - 302 - LRB104 11172 AAS 21254 b
10832	10832	HB3779 - 302 - LRB104 11172 AAS 21254 b
10833	10833	1 the county in which the principal office is located. The
10834	10834	2 recorder of deeds shall record this certified copy and list
10835	10835	3 and shall immediately transmit the certified copy and list to
10836	10836	4 the Secretary of State, together with his certificate of
10837	10837	5 recordation. The Secretary of State shall file these documents
10838	10838	6 and issue his certificate of approval over his signature and
10839	10839	7 the Great Seal of the State. The Secretary of State shall make
10840	10840	8 and keep a register of municipal power agencies established
10841	10841	9 under this Division.
10842	10842	10 C. Each municipality which becomes a member of the
10843	10843	11 municipal power agency shall appoint a representative to serve
10844	10844	12 on the Board of Directors, which representative may be a
10845	10845	13 member of the governing body of the municipality. Each
10846	10846	14 appointment shall be made by the mayor, or president, subject
10847	10847	15 to the confirmation of the governing body. The directors so
10848	10848	16 appointed shall hold office for a term of 3 years, or until a
10849	10849	17 successor has been duly appointed and qualified, except that
10850	10850	18 the directors first appointed shall determine by lot at their
10851	10851	19 initial meeting the respective directors which shall serve for
10852	10852	20 a term of one, 2 or 3 years from the date of that meeting. A
10853	10853	21 vacancy shall be filled for the balance of the unexpired term
10854	10854	22 in the same manner as the original appointment.
10855	10855	23 The Board of Directors is the corporate authority of the
10856	10856	24 municipal power agency and shall exercise all the powers and
10857	10857	25 manage and control all of the affairs and property of the
10858	10858	26 agency. The Board of Directors shall have full power to pass
10859	10859
10860	10860
10861	10861
10862	10862
10863	10863
10864	10864	HB3779 - 302 - LRB104 11172 AAS 21254 b
10865	10865
10866	10866
10867	10867	HB3779- 303 -LRB104 11172 AAS 21254 b HB3779 - 303 - LRB104 11172 AAS 21254 b
10868	10868	HB3779 - 303 - LRB104 11172 AAS 21254 b
10869	10869	1 all necessary ordinances, resolutions, rules and regulations
10870	10870	2 for the proper management and conduct of the business of the
10871	10871	3 board, and for carrying into effect the objects for which the
10872	10872	4 agency was established.
10873	10873	5 At the initial meeting of the Board of Directors to be held
10874	10874	6 within 30 days after the date of establishment of the
10875	10875	7 municipal power agency, the directors shall elect from their
10876	10876	8 members a presiding officer to preside over the meetings of
10877	10877	9 the Board of Directors and an alternative presiding officer
10878	10878	10 and may elect an executive board. The Board of Directors shall
10879	10879	11 determine and designate in the agency's bylaws the titles for
10880	10880	12 the presiding officers. The directors shall also elect a
10881	10881	13 secretary and treasurer, who need not be directors. The board
10882	10882	14 may select such other officers, employees and agents as deemed
10883	10883	15 to be necessary, who need not be directors or residents of any
10884	10884	16 of the municipalities which are members of the municipal power
10885	10885	17 agency. The board may designate appropriate titles for all
10886	10886	18 other officers, employees, and agents. All persons selected by
10887	10887	19 the board shall hold their respective offices during the
10888	10888	20 pleasure of the board, and give such bond as may be required by
10889	10889	21 the board.
10890	10890	22 D. The bylaws of the municipal power agency, and any
10891	10891	23 amendments thereto, shall be adopted by the Board of Directors
10892	10892	24 by a majority vote (adjusted for weighted voting, if provided
10893	10893	25 in the Agency Agreement) to provide the following:
10894	10894	26 (1) the conditions and obligations of membership, if
10895	10895
10896	10896
10897	10897
10898	10898
10899	10899
10900	10900	HB3779 - 303 - LRB104 11172 AAS 21254 b
10901	10901
10902	10902
10903	10903	HB3779- 304 -LRB104 11172 AAS 21254 b HB3779 - 304 - LRB104 11172 AAS 21254 b
10904	10904	HB3779 - 304 - LRB104 11172 AAS 21254 b
10905	10905	1 any;
10906	10906	2 (2) the manner and time of calling regular and special
10907	10907	3 meetings of the Board of Directors;
10908	10908	4 (3) the procedural rules of the Board of Directors;
10909	10909	5 (4) the composition, powers and responsibilities of
10910	10910	6 any committee or executive board;
10911	10911	7 (5) the rights and obligations of new members,
10912	10912	8 conditions for the termination of membership, including a
10913	10913	9 formula for the determination of required termination
10914	10914	10 payments, if any, and the disposition of rights and
10915	10915	11 obligations upon termination of membership; and
10916	10916	12 (6) such other rules or provisions for regulating the
10917	10917	13 affairs of the municipal power agency as the board shall
10918	10918	14 determine to be necessary.
10919	10919	15 E. Every municipal power agency shall maintain an office
10920	10920	16 in the State of Illinois to be known as its principal office.
10921	10921	17 When a municipal power agency desires to change the location
10922	10922	18 of such office, it shall file with the Secretary of State a
10923	10923	19 certificate of change of location, stating the new address and
10924	10924	20 the effective date of change. Meetings of the Board of
10925	10925	21 Directors may be held at any place within the State of
10926	10926	22 Illinois, designated by the Board of Directors, after notice.
10927	10927	23 Unless otherwise provided by the bylaws, an act of the
10928	10928	24 majority of the directors present at a meeting at which a
10929	10929	25 quorum is present is the act of the Board of Directors.
10930	10930	26 F. The Board of Directors shall hold at least one meeting
10931	10931
10932	10932
10933	10933
10934	10934
10935	10935
10936	10936	HB3779 - 304 - LRB104 11172 AAS 21254 b
10937	10937
10938	10938
10939	10939	HB3779- 305 -LRB104 11172 AAS 21254 b HB3779 - 305 - LRB104 11172 AAS 21254 b
10940	10940	HB3779 - 305 - LRB104 11172 AAS 21254 b
10941	10941	1 each year for the election of officers and for the transaction
10942	10942	2 of any other business. Special meetings of the Board of
10943	10943	3 Directors may be called for any purpose upon written request
10944	10944	4 to the presiding officer of the Board of Directors or
10945	10945	5 secretary to call the meeting. Such officer shall give notice
10946	10946	6 of the meeting to be held not less than 10 days and not more
10947	10947	7 than 60 days after receipt of such request. Unless the bylaws
10948	10948	8 provide for a different percentage, a quorum for a meeting of
10949	10949	9 the Board of Directors is a majority of all members then in
10950	10950	10 office. All meetings of the board shall be held in compliance
10951	10951	11 with the provisions of "An Act in relation to meetings",
10952	10952	12 approved July 11, 1957, as amended.
10953	10953	13 G. The agency agreement may be amended as proposed at any
10954	10954	14 meeting of the Board of Directors for which notice, stating
10955	10955	15 the purpose, shall be given to each director and, unless the
10956	10956	16 bylaws prescribe otherwise, such amendment shall become
10957	10957	17 effective when ratified by ordinances adopted by a majority of
10958	10958	18 the governing bodies of the member municipalities. Each
10959	10959	19 amendment, duly certified, shall be recorded and filed in the
10960	10960	20 same manner as for the original agreement.
10961	10961	21 H. Each member municipality shall have full power and
10962	10962	22 authority, subject to the provisions of its charter and laws
10963	10963	23 regarding local finance, to appropriate money for the payment
10964	10964	24 of the expenses of the municipal power agency and of its
10965	10965	25 representative in exercising its functions as a member of the
10966	10966	26 municipal power agency.
10967	10967
10968	10968
10969	10969
10970	10970
10971	10971
10972	10972	HB3779 - 305 - LRB104 11172 AAS 21254 b
10973	10973
10974	10974
10975	10975	HB3779- 306 -LRB104 11172 AAS 21254 b HB3779 - 306 - LRB104 11172 AAS 21254 b
10976	10976	HB3779 - 306 - LRB104 11172 AAS 21254 b
10977	10977	1 I. Any additional municipality which operates an electric
10978	10978	2 utility system may join the municipal power agency, or any
10979	10979	3 member municipality may withdraw therefrom consistent with the
10980	10980	4 bylaws of the municipal power agency, and upon payment of any
10981	10981	5 termination obligations as described in subsection D upon the
10982	10982	6 approval by ordinance adopted by the governing body of the
10983	10983	7 majority of the municipalities which are then members of the
10984	10984	8 municipal power agency. Any new member shall agree to assume
10985	10985	9 its proportionate share of the outstanding obligations of the
10986	10986	10 municipal power agency and any member permitted to withdraw
10987	10987	11 shall remain obligated to make payments under any outstanding
10988	10988	12 contract or agreement with the municipal power agency or to
10989	10989	13 comply with any exit or early termination provisions set forth
10990	10990	14 in that contract or agreement. Any such change in membership
10991	10991	15 shall be recorded and filed in the same manner as for the
10992	10992	16 original agreement.
10993	10993	17 J. Any 2 or more municipal power agencies organized
10994	10994	18 pursuant to this Division may consolidate to form a new
10995	10995	19 municipal power agency when approved by ordinance adopted by
10996	10996	20 the governing body of each municipality which is a member of
10997	10997	21 the respective municipal power agency and by the execution of
10998	10998	22 an agency agreement as provided in this Section.
10999	10999	23 (Source: P.A. 96-204, eff. 1-1-10.)
11000	11000	24 (65 ILCS 5/11-119.1-5.5 new)
11001	11001	25 Sec. 11-119.1-5.5. Agency records, budgets, and quarterly
11002	11002
11003	11003
11004	11004
11005	11005
11006	11006
11007	11007	HB3779 - 306 - LRB104 11172 AAS 21254 b
11008	11008
11009	11009
11010	11010	HB3779- 307 -LRB104 11172 AAS 21254 b HB3779 - 307 - LRB104 11172 AAS 21254 b
11011	11011	HB3779 - 307 - LRB104 11172 AAS 21254 b
11012	11012	1 reports.
11013	11013	2 (a) A municipal power agency shall keep accurate accounts
11014	11014	3 and records of its assets, liabilities, revenues, and
11015	11015	4 expenditures in accordance with generally accepted accounting
11016	11016	5 principles. Such accounts and records shall include, but are
11017	11017	6 not limited to, depreciation, operating and maintenance
11018	11018	7 expenses for all generation and transmission assets, fuel
11019	11019	8 costs, cost and revenue from the purchase or sale of
11020	11020	9 environmental compliance credits, revenue from energy,
11021	11021	10 capacity, and ancillary market sales, all payments received
11022	11022	11 from member municipalities, membership dues or other payments
11023	11023	12 made to trade associations or industry organizations, and
11024	11024	13 lobbying expenditures. Such records shall be audited on an
11025	11025	14 annual basis by an independent auditor using generally
11026	11026	15 accepted auditing standards and shall include contents as set
11027	11027	16 forth in Section 8-8-5, and shall be filed with the
11028	11028	17 Comptroller as described by Section 8-8-7.
11029	11029	18 (b) A municipal power agency shall, on an annual basis,
11030	11030	19 prepare one-year and 5-year budgets that include all revenues
11031	11031	20 and expenses, including, but not limited to, those categories
11032	11032	21 described in subsection (a). As part of each one-year budget,
11033	11033	22 the municipal power agency shall include a report identifying
11034	11034	23 and explaining any variance from the previous annual budget of
11035	11035	24 5% or greater in any expenditure or revenue line item. Such
11036	11036	25 budgets shall be provided to member municipalities no less
11037	11037	26 than 60 days prior to any meeting of the municipal power agency
11038	11038
11039	11039
11040	11040
11041	11041
11042	11042
11043	11043	HB3779 - 307 - LRB104 11172 AAS 21254 b
11044	11044
11045	11045
11046	11046	HB3779- 308 -LRB104 11172 AAS 21254 b HB3779 - 308 - LRB104 11172 AAS 21254 b
11047	11047	HB3779 - 308 - LRB104 11172 AAS 21254 b
11048	11048	1 during which action on the budget is or will be part of the
11049	11049	2 agency agenda.
11050	11050	3 (c) The municipal power agency shall post, on a publicly
11051	11051	4 available website, all one-year and 5-year budgets required
11052	11052	5 under subsection (b) and the annual audited financial
11053	11053	6 statements required under subsection (a).
11054	11054	7 (d) The municipal power agency shall make available, upon
11055	11055	8 request to any of its member municipalities, access to all
11056	11056	9 municipal power agency all records and accounts and all
11057	11057	10 financial information relating to ownership and operation of
11058	11058	11 agency assets and the generation, procurement, and delivery of
11059	11059	12 electricity to which the agency has access, including, but not
11060	11060	13 limited to, unit scheduling information, market revenue and
11061	11061	14 off-system sales data, and fuel and other variable cost
11062	11062	15 information. Such information shall be provided in a timely
11063	11063	16 manner and through reasonable means, and members shall be
11064	11064	17 permitted to make copies of any documents retained solely by
11065	11065	18 the agency. Such access shall be provided without regard to
11066	11066	19 any nondisclosure agreement that has been or may be adopted by
11067	11067	20 the municipal power agency.
11068	11068	21 (e) The municipal power agency shall prepare, on a
11069	11069	22 quarterly basis, a report to its member municipalities
11070	11070	23 describing all expenditures made for the purpose of lobbying,
11071	11071	24 as both terms are defined by Section 2 of the Lobbyist
11072	11072	25 Registration Act, and a brief summary of the topics and
11073	11073	26 positions on which lobbying activities were undertaken. Where
11074	11074
11075	11075
11076	11076
11077	11077
11078	11078
11079	11079	HB3779 - 308 - LRB104 11172 AAS 21254 b
11080	11080
11081	11081
11082	11082	HB3779- 309 -LRB104 11172 AAS 21254 b HB3779 - 309 - LRB104 11172 AAS 21254 b
11083	11083	HB3779 - 309 - LRB104 11172 AAS 21254 b
11084	11084	1 the municipal power agency is a member of an organization or
11085	11085	2 trade association that expends some or all of membership dues
11086	11086	3 on lobbying activities, the municipal power agency shall
11087	11087	4 include in this report the amount of those membership dues,
11088	11088	5 what proportion of those dues were spent on lobbying
11089	11089	6 activities, and the topics and positions on which lobbying
11090	11090	7 activities were undertaken by the organization or trade
11091	11091	8 association of which the municipal power agency is a member.
11092	11092	9 (65 ILCS 5/11-119.1-10) (from Ch. 24, par. 11-119.1-10)
11093	11093	10 Sec. 11-119.1-10. Exercise of powers. A municipal power
11094	11094	11 agency may exercise any and all of the powers enumerated in
11095	11095	12 this Division, except the power of eminent domain, without the
11096	11096	13 consent and approval of the Illinois Commerce Commission. The
11097	11097	14 exercise of the power of eminent domain by a municipal power
11098	11098	15 agency shall be subject to the consent and approval of the
11099	11099	16 Illinois Commerce Commission in the same manner and to the
11100	11100	17 same extent as public utilities under the Public Utilities
11101	11101	18 Act, including the issuance of a certificate of public
11102	11102	19 convenience and necessity as provided for in Section 8-406 of
11103	11103	20 that Act. During the consideration of any petition for
11104	11104	21 authority to exercise the power of eminent domain the Illinois
11105	11105	22 Commerce Commission shall evaluate and give due consideration
11106	11106	23 to whether the project for which eminent domain is sought is
11107	11107	24 part of the preferred portfolio as described in subsection (d)
11108	11108	25 of Section 15 of the Municipal and Cooperative Electric
11109	11109
11110	11110
11111	11111
11112	11112
11113	11113
11114	11114	HB3779 - 309 - LRB104 11172 AAS 21254 b
11115	11115
11116	11116
11117	11117	HB3779- 310 -LRB104 11172 AAS 21254 b HB3779 - 310 - LRB104 11172 AAS 21254 b
11118	11118	HB3779 - 310 - LRB104 11172 AAS 21254 b
11119	11119	1 Utility Planning and Transparency Act, or least cost plans for
11120	11120	2 procuring renewable resources as described in subsections (f)
11121	11121	3 and (g) of Section 20 of the Municipal and Cooperative
11122	11122	4 Electric Utility Planning and Transparency Act and to the
11123	11123	5 impact of the acquisition on farmlands in the State with the
11124	11124	6 goal of preserving the land to the fullest extent reasonably
11125	11125	7 possible.
11126	11126	8 (Source: P.A. 90-416, eff. 1-1-98.)
11127	11127	9 Section 115. The Public Utilities Act is amended by
11128	11128	10 changing Sections 3-105, 8-103B, 8-406, 8-406.1, 8-512, 9-229,
11129	11129	11 16-107.5, 16-108, 16-108.30, 16-111.5, 16-115A, 16-115D,
11130	11130	12 17-500, and 17-900 and by adding Sections 8-104B, 16-107.7A,
11131	11131	13 and 16-107.8 as follows:
11132	11132	14 (220 ILCS 5/3-105) (from Ch. 111 2/3, par. 3-105)
11133	11133	15 Sec. 3-105. Public utility.
11134	11134	16 (a) "Public utility" means and includes, except where
11135	11135	17 otherwise expressly provided in this Section, every
11136	11136	18 corporation, company, limited liability company, association,
11137	11137	19 joint stock company or association, firm, partnership or
11138	11138	20 individual, their lessees, trustees, or receivers appointed by
11139	11139	21 any court whatsoever now or hereafter that owns, controls,
11140	11140	22 operates or manages, within this State, directly or
11141	11141	23 indirectly, for public use, any plant, equipment or property
11142	11142	24 used or to be used for or in connection with, or owns or
11143	11143
11144	11144
11145	11145
11146	11146
11147	11147
11148	11148	HB3779 - 310 - LRB104 11172 AAS 21254 b
11149	11149
11150	11150
11151	11151	HB3779- 311 -LRB104 11172 AAS 21254 b HB3779 - 311 - LRB104 11172 AAS 21254 b
11152	11152	HB3779 - 311 - LRB104 11172 AAS 21254 b
11153	11153	1 controls or seeks Commission approval to own or control any
11154	11154	2 franchise, license, permit or right to engage in:
11155	11155	3 (1) the production, storage, transmission, sale,
11156	11156	4 delivery or furnishing of heat, cold, power, electricity,
11157	11157	5 water, or light, except when used solely for
11158	11158	6 communications purposes;
11159	11159	7 (2) the disposal of sewerage; or
11160	11160	8 (3) the conveyance of oil or gas by pipe line.
11161	11161	9 (b) "Public utility" does not include, however:
11162	11162	10 (1) public utilities that are owned and operated by
11163	11163	11 any political subdivision, public institution of higher
11164	11164	12 education or municipal corporation of this State, or
11165	11165	13 public utilities that are owned by such political
11166	11166	14 subdivision, public institution of higher education, or
11167	11167	15 municipal corporation and operated by any of its lessees
11168	11168	16 or operating agents;
11169	11169	17 (2) water companies which are purely mutual concerns,
11170	11170	18 having no rates or charges for services, but paying the
11171	11171	19 operating expenses by assessment upon the members of such
11172	11172	20 a company and no other person;
11173	11173	21 (3) electric cooperatives as defined in Section 3-119;
11174	11174	22 (4) the following natural gas cooperatives:
11175	11175	23 (A) residential natural gas cooperatives that are
11176	11176	24 not-for-profit corporations established for the
11177	11177	25 purpose of administering and operating, on a
11178	11178	26 cooperative basis, the furnishing of natural gas to
11179	11179
11180	11180
11181	11181
11182	11182
11183	11183
11184	11184	HB3779 - 311 - LRB104 11172 AAS 21254 b
11185	11185
11186	11186
11187	11187	HB3779- 312 -LRB104 11172 AAS 21254 b HB3779 - 312 - LRB104 11172 AAS 21254 b
11188	11188	HB3779 - 312 - LRB104 11172 AAS 21254 b
11189	11189	1 residences for the benefit of their members who are
11190	11190	2 residential consumers of natural gas. For entities
11191	11191	3 qualifying as residential natural gas cooperatives and
11192	11192	4 recognized by the Illinois Commerce Commission as
11193	11193	5 such, the State shall guarantee legally binding
11194	11194	6 contracts entered into by residential natural gas
11195	11195	7 cooperatives for the express purpose of acquiring
11196	11196	8 natural gas supplies for their members. The Illinois
11197	11197	9 Commerce Commission shall establish rules and
11198	11198	10 regulations providing for such guarantees. The total
11199	11199	11 liability of the State in providing all such
11200	11200	12 guarantees shall not at any time exceed $1,000,000,
11201	11201	13 nor shall the State provide such a guarantee to a
11202	11202	14 residential natural gas cooperative for more than 3
11203	11203	15 consecutive years; and
11204	11204	16 (B) natural gas cooperatives that are
11205	11205	17 not-for-profit corporations operated for the purpose
11206	11206	18 of administering, on a cooperative basis, the
11207	11207	19 furnishing of natural gas for the benefit of their
11208	11208	20 members and that, prior to 90 days after the effective
11209	11209	21 date of this amendatory Act of the 94th General
11210	11210	22 Assembly, either had acquired or had entered into an
11211	11211	23 asset purchase agreement to acquire all or
11212	11212	24 substantially all of the operating assets of a public
11213	11213	25 utility or natural gas cooperative with the intention
11214	11214	26 of operating those assets as a natural gas
11215	11215
11216	11216
11217	11217
11218	11218
11219	11219
11220	11220	HB3779 - 312 - LRB104 11172 AAS 21254 b
11221	11221
11222	11222
11223	11223	HB3779- 313 -LRB104 11172 AAS 21254 b HB3779 - 313 - LRB104 11172 AAS 21254 b
11224	11224	HB3779 - 313 - LRB104 11172 AAS 21254 b
11225	11225	1 cooperative;
11226	11226	2 (5) sewage disposal companies which provide sewage
11227	11227	3 disposal services on a mutual basis without establishing
11228	11228	4 rates or charges for services, but paying the operating
11229	11229	5 expenses by assessment upon the members of the company and
11230	11230	6 no others;
11231	11231	7 (6) (blank);
11232	11232	8 (7) cogeneration facilities, small power production
11233	11233	9 facilities, and other qualifying facilities, as defined in
11234	11234	10 the Public Utility Regulatory Policies Act and regulations
11235	11235	11 promulgated thereunder, except to the extent State
11236	11236	12 regulatory jurisdiction and action is required or
11237	11237	13 authorized by federal law, regulations, regulatory
11238	11238	14 decisions or the decisions of federal or State courts of
11239	11239	15 competent jurisdiction;
11240	11240	16 (8) the ownership or operation of a facility that
11241	11241	17 sells compressed natural gas at retail to the public for
11242	11242	18 use only as a motor vehicle fuel and the selling of
11243	11243	19 compressed natural gas at retail to the public for use
11244	11244	20 only as a motor vehicle fuel;
11245	11245	21 (9) alternative retail electric suppliers as defined
11246	11246	22 in Article XVI; and
11247	11247	23 (10) the Illinois Power Agency.
11248	11248	24 (c) An entity that furnishes the service of charging
11249	11249	25 electric vehicles does not and shall not be deemed to sell
11250	11250	26 electricity and is not and shall not be deemed a public utility
11251	11251
11252	11252
11253	11253
11254	11254
11255	11255
11256	11256	HB3779 - 313 - LRB104 11172 AAS 21254 b
11257	11257
11258	11258
11259	11259	HB3779- 314 -LRB104 11172 AAS 21254 b HB3779 - 314 - LRB104 11172 AAS 21254 b
11260	11260	HB3779 - 314 - LRB104 11172 AAS 21254 b
11261	11261	1 notwithstanding the basis on which the service is provided or
11262	11262	2 billed. If, however, the entity is otherwise deemed a public
11263	11263	3 utility under this Act, or is otherwise subject to regulation
11264	11264	4 under this Act, then that entity is not exempt from and remains
11265	11265	5 subject to the otherwise applicable provisions of this Act.
11266	11266	6 The installation, maintenance, and repair of an electric
11267	11267	7 vehicle charging station shall comply with the requirements of
11268	11268	8 subsection (a) of Section 16-128 and Section 16-128A of this
11269	11269	9 Act.
11270	11270	10 For purposes of this subsection, the term "electric
11271	11271	11 vehicles" has the meaning ascribed to that term in Section 10
11272	11272	12 of the Electric Vehicle Act.
11273	11273	13 (Source: P.A. 97-1128, eff. 8-28-12.)
11274	11274	14 (220 ILCS 5/8-103B)
11275	11275	15 Sec. 8-103B. Energy efficiency and demand-response
11276	11276	16 measures.
11277	11277	17 (a) It is the policy of the State that electric utilities
11278	11278	18 are required to use cost-effective energy efficiency and
11279	11279	19 demand-response measures to reduce delivery load. Requiring
11280	11280	20 investment in cost-effective energy efficiency and
11281	11281	21 demand-response measures will reduce direct and indirect costs
11282	11282	22 to consumers by decreasing environmental impacts and by
11283	11283	23 avoiding or delaying the need for new generation,
11284	11284	24 transmission, and distribution infrastructure. It serves the
11285	11285	25 public interest to allow electric utilities to recover costs
11286	11286
11287	11287
11288	11288
11289	11289
11290	11290
11291	11291	HB3779 - 314 - LRB104 11172 AAS 21254 b
11292	11292
11293	11293
11294	11294	HB3779- 315 -LRB104 11172 AAS 21254 b HB3779 - 315 - LRB104 11172 AAS 21254 b
11295	11295	HB3779 - 315 - LRB104 11172 AAS 21254 b
11296	11296	1 for reasonably and prudently incurred expenditures for energy
11297	11297	2 efficiency and demand-response measures. As used in this
11298	11298	3 Section, "cost-effective" means that the measures satisfy the
11299	11299	4 total resource cost test. The low-income measures described in
11300	11300	5 subsection (c) of this Section shall not be required to meet
11301	11301	6 the total resource cost test. For purposes of this Section,
11302	11302	7 the terms "energy-efficiency", "demand-response", "electric
11303	11303	8 utility", and "total resource cost test" have the meanings set
11304	11304	9 forth in the Illinois Power Agency Act. "Black, indigenous,
11305	11305	10 and people of color" and "BIPOC" means people who are members
11306	11306	11 of the groups described in subparagraphs (a) through (e) of
11307	11307	12 paragraph (A) of subsection (1) of Section 2 of the Business
11308	11308	13 Enterprise for Minorities, Women, and Persons with
11309	11309	14 Disabilities Act.
11310	11310	15 (a-5) This Section applies to electric utilities serving
11311	11311	16 more than 500,000 retail customers in the State for those
11312	11312	17 multi-year plans commencing after December 31, 2017.
11313	11313	18 (b) For purposes of this Section, through calendar year
11314	11314	19 2026, electric utilities subject to this Section that serve
11315	11315	20 more than 3,000,000 retail customers in the State shall be
11316	11316	21 deemed to have achieved a cumulative persisting annual savings
11317	11317	22 of 6.6% from energy efficiency measures and programs
11318	11318	23 implemented during the period beginning January 1, 2012 and
11319	11319	24 ending December 31, 2017, which percent is based on the deemed
11320	11320	25 average weather normalized sales of electric power and energy
11321	11321	26 during calendar years 2014, 2015, and 2016 of 88,000,000 MWhs.
11322	11322
11323	11323
11324	11324
11325	11325
11326	11326
11327	11327	HB3779 - 315 - LRB104 11172 AAS 21254 b
11328	11328
11329	11329
11330	11330	HB3779- 316 -LRB104 11172 AAS 21254 b HB3779 - 316 - LRB104 11172 AAS 21254 b
11331	11331	HB3779 - 316 - LRB104 11172 AAS 21254 b
11332	11332	1 For the purposes of this subsection (b) and subsection (b-5),
11333	11333	2 the 88,000,000 MWhs of deemed electric power and energy sales
11334	11334	3 shall be reduced by the number of MWhs equal to the sum of the
11335	11335	4 annual consumption of customers that have opted out of
11336	11336	5 subsections (a) through (j) of this Section under paragraph
11337	11337	6 (1) of subsection (l) of this Section, as averaged across the
11338	11338	7 calendar years 2014, 2015, and 2016. After 2017, the deemed
11339	11339	8 value of cumulative persisting annual savings from energy
11340	11340	9 efficiency measures and programs implemented during the period
11341	11341	10 beginning January 1, 2012 and ending December 31, 2017, shall
11342	11342	11 be reduced each year, as follows, and the applicable value
11343	11343	12 shall be applied to and count toward the utility's achievement
11344	11344	13 of the cumulative persisting annual savings goals set forth in
11345	11345	14 subsection (b-5):
11346	11346	15 (1) 5.8% deemed cumulative persisting annual savings
11347	11347	16 for the year ending December 31, 2018;
11348	11348	17 (2) 5.2% deemed cumulative persisting annual savings
11349	11349	18 for the year ending December 31, 2019;
11350	11350	19 (3) 4.5% deemed cumulative persisting annual savings
11351	11351	20 for the year ending December 31, 2020;
11352	11352	21 (4) 4.0% deemed cumulative persisting annual savings
11353	11353	22 for the year ending December 31, 2021;
11354	11354	23 (5) 3.5% deemed cumulative persisting annual savings
11355	11355	24 for the year ending December 31, 2022;
11356	11356	25 (6) 3.1% deemed cumulative persisting annual savings
11357	11357	26 for the year ending December 31, 2023;
11358	11358
11359	11359
11360	11360
11361	11361
11362	11362
11363	11363	HB3779 - 316 - LRB104 11172 AAS 21254 b
11364	11364
11365	11365
11366	11366	HB3779- 317 -LRB104 11172 AAS 21254 b HB3779 - 317 - LRB104 11172 AAS 21254 b
11367	11367	HB3779 - 317 - LRB104 11172 AAS 21254 b
11368	11368	1 (7) 2.8% deemed cumulative persisting annual savings
11369	11369	2 for the year ending December 31, 2024; and
11370	11370	3 (8) 2.5% deemed cumulative persisting annual savings
11371	11371	4 for the year ending December 31, 2025. ;
11372	11372	5 (9) 2.3% deemed cumulative persisting annual savings
11373	11373	6 for the year ending December 31, 2026;
11374	11374	7 (10) 2.1% deemed cumulative persisting annual savings
11375	11375	8 for the year ending December 31, 2027;
11376	11376	9 (11) 1.8% deemed cumulative persisting annual savings
11377	11377	10 for the year ending December 31, 2028;
11378	11378	11 (12) 1.7% deemed cumulative persisting annual savings
11379	11379	12 for the year ending December 31, 2029;
11380	11380	13 (13) 1.5% deemed cumulative persisting annual savings
11381	11381	14 for the year ending December 31, 2030;
11382	11382	15 (14) 1.3% deemed cumulative persisting annual savings
11383	11383	16 for the year ending December 31, 2031;
11384	11384	17 (15) 1.1% deemed cumulative persisting annual savings
11385	11385	18 for the year ending December 31, 2032;
11386	11386	19 (16) 0.9% deemed cumulative persisting annual savings
11387	11387	20 for the year ending December 31, 2033;
11388	11388	21 (17) 0.7% deemed cumulative persisting annual savings
11389	11389	22 for the year ending December 31, 2034;
11390	11390	23 (18) 0.5% deemed cumulative persisting annual savings
11391	11391	24 for the year ending December 31, 2035;
11392	11392	25 (19) 0.4% deemed cumulative persisting annual savings
11393	11393	26 for the year ending December 31, 2036;
11394	11394
11395	11395
11396	11396
11397	11397
11398	11398
11399	11399	HB3779 - 317 - LRB104 11172 AAS 21254 b
11400	11400
11401	11401
11402	11402	HB3779- 318 -LRB104 11172 AAS 21254 b HB3779 - 318 - LRB104 11172 AAS 21254 b
11403	11403	HB3779 - 318 - LRB104 11172 AAS 21254 b
11404	11404	1 (20) 0.3% deemed cumulative persisting annual savings
11405	11405	2 for the year ending December 31, 2037;
11406	11406	3 (21) 0.2% deemed cumulative persisting annual savings
11407	11407	4 for the year ending December 31, 2038;
11408	11408	5 (22) 0.1% deemed cumulative persisting annual savings
11409	11409	6 for the year ending December 31, 2039; and
11410	11410	7 (23) 0.0% deemed cumulative persisting annual savings
11411	11411	8 for the year ending December 31, 2040 and all subsequent
11412	11412	9 years.
11413	11413	10 For purposes of this Section, "cumulative persisting
11414	11414	11 annual savings" means the total electric energy savings in a
11415	11415	12 given year from measures installed in that year or in previous
11416	11416	13 years, but no earlier than January 1, 2012, that are still
11417	11417	14 operational and providing savings in that year because the
11418	11418	15 measures have not yet reached the end of their useful lives.
11419	11419	16 (b-5) Beginning in 2018, through calendar year 2026,
11420	11420	17 electric utilities subject to this Section that serve more
11421	11421	18 than 3,000,000 retail customers in the State shall achieve the
11422	11422	19 following cumulative persisting annual savings goals, as
11423	11423	20 modified by subsection (f) of this Section and as compared to
11424	11424	21 the deemed baseline of 88,000,000 MWhs of electric power and
11425	11425	22 energy sales set forth in subsection (b), as reduced by the
11426	11426	23 number of MWhs equal to the sum of the annual consumption of
11427	11427	24 customers that have opted out of subsections (a) through (j)
11428	11428	25 of this Section under paragraph (1) of subsection (l) of this
11429	11429	26 Section as averaged across the calendar years 2014, 2015, and
11430	11430
11431	11431
11432	11432
11433	11433
11434	11434
11435	11435	HB3779 - 318 - LRB104 11172 AAS 21254 b
11436	11436
11437	11437
11438	11438	HB3779- 319 -LRB104 11172 AAS 21254 b HB3779 - 319 - LRB104 11172 AAS 21254 b
11439	11439	HB3779 - 319 - LRB104 11172 AAS 21254 b
11440	11440	1 2016, through the implementation of energy efficiency measures
11441	11441	2 during the applicable year and in prior years, but no earlier
11442	11442	3 than January 1, 2012:
11443	11443	4 (1) 7.8% cumulative persisting annual savings for the
11444	11444	5 year ending December 31, 2018;
11445	11445	6 (2) 9.1% cumulative persisting annual savings for the
11446	11446	7 year ending December 31, 2019;
11447	11447	8 (3) 10.4% cumulative persisting annual savings for the
11448	11448	9 year ending December 31, 2020;
11449	11449	10 (4) 11.8% cumulative persisting annual savings for the
11450	11450	11 year ending December 31, 2021;
11451	11451	12 (5) 13.1% cumulative persisting annual savings for the
11452	11452	13 year ending December 31, 2022;
11453	11453	14 (6) 14.4% cumulative persisting annual savings for the
11454	11454	15 year ending December 31, 2023;
11455	11455	16 (7) 15.7% cumulative persisting annual savings for the
11456	11456	17 year ending December 31, 2024; and
11457	11457	18 (8) 17% cumulative persisting annual savings for the
11458	11458	19 year ending December 31, 2025. ;
11459	11459	20 (9) 17.9% cumulative persisting annual savings for the
11460	11460	21 year ending December 31, 2026;
11461	11461	22 (10) 18.8% cumulative persisting annual savings for
11462	11462	23 the year ending December 31, 2027;
11463	11463	24 (11) 19.7% cumulative persisting annual savings for
11464	11464	25 the year ending December 31, 2028;
11465	11465	26 (12) 20.6% cumulative persisting annual savings for
11466	11466
11467	11467
11468	11468
11469	11469
11470	11470
11471	11471	HB3779 - 319 - LRB104 11172 AAS 21254 b
11472	11472
11473	11473
11474	11474	HB3779- 320 -LRB104 11172 AAS 21254 b HB3779 - 320 - LRB104 11172 AAS 21254 b
11475	11475	HB3779 - 320 - LRB104 11172 AAS 21254 b
11476	11476	1 the year ending December 31, 2029; and
11477	11477	2 (13) 21.5% cumulative persisting annual savings for
11478	11478	3 the year ending December 31, 2030.
11479	11479	4 No later than December 31, 2021, the Illinois Commerce
11480	11480	5 Commission shall establish additional cumulative persisting
11481	11481	6 annual savings goals for the years 2031 through 2035. No later
11482	11482	7 than December 31, 2024, the Illinois Commerce Commission shall
11483	11483	8 establish additional cumulative persisting annual savings
11484	11484	9 goals for the years 2036 through 2040. The Commission shall
11485	11485	10 also establish additional cumulative persisting annual savings
11486	11486	11 goals every 5 years thereafter to ensure that utilities always
11487	11487	12 have goals that extend at least 11 years into the future. The
11488	11488	13 cumulative persisting annual savings goals beyond the year
11489	11489	14 2030 shall increase by 0.9 percentage points per year, absent
11490	11490	15 a Commission decision to initiate a proceeding to consider
11491	11491	16 establishing goals that increase by more or less than that
11492	11492	17 amount. Such a proceeding must be conducted in accordance with
11493	11493	18 the procedures described in subsection (f) of this Section. If
11494	11494	19 such a proceeding is initiated, the cumulative persisting
11495	11495	20 annual savings goals established by the Commission through
11496	11496	21 that proceeding shall reflect the Commission's best estimate
11497	11497	22 of the maximum amount of additional savings that are forecast
11498	11498	23 to be cost-effectively achievable unless such best estimates
11499	11499	24 would result in goals that represent less than 0.5 percentage
11500	11500	25 point annual increases in total cumulative persisting annual
11501	11501	26 savings. The Commission may only establish goals that
11502	11502
11503	11503
11504	11504
11505	11505
11506	11506
11507	11507	HB3779 - 320 - LRB104 11172 AAS 21254 b
11508	11508
11509	11509
11510	11510	HB3779- 321 -LRB104 11172 AAS 21254 b HB3779 - 321 - LRB104 11172 AAS 21254 b
11511	11511	HB3779 - 321 - LRB104 11172 AAS 21254 b
11512	11512	1 represent less than 0.5 percentage point annual increases in
11513	11513	2 cumulative persisting annual savings if it can demonstrate,
11514	11514	3 based on clear and convincing evidence and through independent
11515	11515	4 analysis, that 0.5 percentage point increases are not
11516	11516	5 cost-effectively achievable. The Commission shall inform its
11517	11517	6 decision based on an energy efficiency potential study that
11518	11518	7 conforms to the requirements of this Section.
11519	11519	8 (b-10) For purposes of this Section, through calendar year
11520	11520	9 2026, electric utilities subject to this Section that serve
11521	11521	10 less than 3,000,000 retail customers but more than 500,000
11522	11522	11 retail customers in the State shall be deemed to have achieved
11523	11523	12 a cumulative persisting annual savings of 6.6% from energy
11524	11524	13 efficiency measures and programs implemented during the period
11525	11525	14 beginning January 1, 2012 and ending December 31, 2017, which
11526	11526	15 is based on the deemed average weather normalized sales of
11527	11527	16 electric power and energy during calendar years 2014, 2015,
11528	11528	17 and 2016 of 36,900,000 MWhs. For the purposes of this
11529	11529	18 subsection (b-10) and subsection (b-15), the 36,900,000 MWhs
11530	11530	19 of deemed electric power and energy sales shall be reduced by
11531	11531	20 the number of MWhs equal to the sum of the annual consumption
11532	11532	21 of customers that have opted out of subsections (a) through
11533	11533	22 (j) of this Section under paragraph (1) of subsection (l) of
11534	11534	23 this Section, as averaged across the calendar years 2014,
11535	11535	24 2015, and 2016. After 2017, the deemed value of cumulative
11536	11536	25 persisting annual savings from energy efficiency measures and
11537	11537	26 programs implemented during the period beginning January 1,
11538	11538
11539	11539
11540	11540
11541	11541
11542	11542
11543	11543	HB3779 - 321 - LRB104 11172 AAS 21254 b
11544	11544
11545	11545
11546	11546	HB3779- 322 -LRB104 11172 AAS 21254 b HB3779 - 322 - LRB104 11172 AAS 21254 b
11547	11547	HB3779 - 322 - LRB104 11172 AAS 21254 b
11548	11548	1 2012 and ending December 31, 2017, shall be reduced each year,
11549	11549	2 as follows, and the applicable value shall be applied to and
11550	11550	3 count toward the utility's achievement of the cumulative
11551	11551	4 persisting annual savings goals set forth in subsection
11552	11552	5 (b-15):
11553	11553	6 (1) 5.8% deemed cumulative persisting annual savings
11554	11554	7 for the year ending December 31, 2018;
11555	11555	8 (2) 5.2% deemed cumulative persisting annual savings
11556	11556	9 for the year ending December 31, 2019;
11557	11557	10 (3) 4.5% deemed cumulative persisting annual savings
11558	11558	11 for the year ending December 31, 2020;
11559	11559	12 (4) 4.0% deemed cumulative persisting annual savings
11560	11560	13 for the year ending December 31, 2021;
11561	11561	14 (5) 3.5% deemed cumulative persisting annual savings
11562	11562	15 for the year ending December 31, 2022;
11563	11563	16 (6) 3.1% deemed cumulative persisting annual savings
11564	11564	17 for the year ending December 31, 2023;
11565	11565	18 (7) 2.8% deemed cumulative persisting annual savings
11566	11566	19 for the year ending December 31, 2024; and
11567	11567	20 (8) 2.5% deemed cumulative persisting annual savings
11568	11568	21 for the year ending December 31, 2025; and
11569	11569	22 (9) 2.3% deemed cumulative persisting annual savings
11570	11570	23 for the year ending December 31, 2026. ;
11571	11571	24 (10) 2.1% deemed cumulative persisting annual savings
11572	11572	25 for the year ending December 31, 2027;
11573	11573	26 (11) 1.8% deemed cumulative persisting annual savings
11574	11574
11575	11575
11576	11576
11577	11577
11578	11578
11579	11579	HB3779 - 322 - LRB104 11172 AAS 21254 b
11580	11580
11581	11581
11582	11582	HB3779- 323 -LRB104 11172 AAS 21254 b HB3779 - 323 - LRB104 11172 AAS 21254 b
11583	11583	HB3779 - 323 - LRB104 11172 AAS 21254 b
11584	11584	1 for the year ending December 31, 2028;
11585	11585	2 (12) 1.7% deemed cumulative persisting annual savings
11586	11586	3 for the year ending December 31, 2029;
11587	11587	4 (13) 1.5% deemed cumulative persisting annual savings
11588	11588	5 for the year ending December 31, 2030;
11589	11589	6 (14) 1.3% deemed cumulative persisting annual savings
11590	11590	7 for the year ending December 31, 2031;
11591	11591	8 (15) 1.1% deemed cumulative persisting annual savings
11592	11592	9 for the year ending December 31, 2032;
11593	11593	10 (16) 0.9% deemed cumulative persisting annual savings
11594	11594	11 for the year ending December 31, 2033;
11595	11595	12 (17) 0.7% deemed cumulative persisting annual savings
11596	11596	13 for the year ending December 31, 2034;
11597	11597	14 (18) 0.5% deemed cumulative persisting annual savings
11598	11598	15 for the year ending December 31, 2035;
11599	11599	16 (19) 0.4% deemed cumulative persisting annual savings
11600	11600	17 for the year ending December 31, 2036;
11601	11601	18 (20) 0.3% deemed cumulative persisting annual savings
11602	11602	19 for the year ending December 31, 2037;
11603	11603	20 (21) 0.2% deemed cumulative persisting annual savings
11604	11604	21 for the year ending December 31, 2038;
11605	11605	22 (22) 0.1% deemed cumulative persisting annual savings
11606	11606	23 for the year ending December 31, 2039; and
11607	11607	24 (23) 0.0% deemed cumulative persisting annual savings
11608	11608	25 for the year ending December 31, 2040 and all subsequent
11609	11609	26 years.
11610	11610
11611	11611
11612	11612
11613	11613
11614	11614
11615	11615	HB3779 - 323 - LRB104 11172 AAS 21254 b
11616	11616
11617	11617
11618	11618	HB3779- 324 -LRB104 11172 AAS 21254 b HB3779 - 324 - LRB104 11172 AAS 21254 b
11619	11619	HB3779 - 324 - LRB104 11172 AAS 21254 b
11620	11620	1 (b-15) Beginning in 2018 and through calendar year 2026,
11621	11621	2 electric utilities subject to this Section that serve less
11622	11622	3 than 3,000,000 retail customers but more than 500,000 retail
11623	11623	4 customers in the State shall achieve the following cumulative
11624	11624	5 persisting annual savings goals, as modified by subsection
11625	11625	6 (b-20) and subsection (f) of this Section and as compared to
11626	11626	7 the deemed baseline as reduced by the number of MWhs equal to
11627	11627	8 the sum of the annual consumption of customers that have opted
11628	11628	9 out of subsections (a) through (j) of this Section under
11629	11629	10 paragraph (1) of subsection (l) of this Section as averaged
11630	11630	11 across the calendar years 2014, 2015, and 2016, through the
11631	11631	12 implementation of energy efficiency measures during the
11632	11632	13 applicable year and in prior years, but no earlier than
11633	11633	14 January 1, 2012:
11634	11634	15 (1) 7.4% cumulative persisting annual savings for the
11635	11635	16 year ending December 31, 2018;
11636	11636	17 (2) 8.2% cumulative persisting annual savings for the
11637	11637	18 year ending December 31, 2019;
11638	11638	19 (3) 9.0% cumulative persisting annual savings for the
11639	11639	20 year ending December 31, 2020;
11640	11640	21 (4) 9.8% cumulative persisting annual savings for the
11641	11641	22 year ending December 31, 2021;
11642	11642	23 (5) 10.6% cumulative persisting annual savings for the
11643	11643	24 year ending December 31, 2022;
11644	11644	25 (6) 11.4% cumulative persisting annual savings for the
11645	11645	26 year ending December 31, 2023;
11646	11646
11647	11647
11648	11648
11649	11649
11650	11650
11651	11651	HB3779 - 324 - LRB104 11172 AAS 21254 b
11652	11652
11653	11653
11654	11654	HB3779- 325 -LRB104 11172 AAS 21254 b HB3779 - 325 - LRB104 11172 AAS 21254 b
11655	11655	HB3779 - 325 - LRB104 11172 AAS 21254 b
11656	11656	1 (7) 12.2% cumulative persisting annual savings for the
11657	11657	2 year ending December 31, 2024;
11658	11658	3 (8) 13% cumulative persisting annual savings for the
11659	11659	4 year ending December 31, 2025; and
11660	11660	5 (9) 13.6% cumulative persisting annual savings for the
11661	11661	6 year ending December 31, 2026. ;
11662	11662	7 (10) 14.2% cumulative persisting annual savings for
11663	11663	8 the year ending December 31, 2027;
11664	11664	9 (11) 14.8% cumulative persisting annual savings for
11665	11665	10 the year ending December 31, 2028;
11666	11666	11 (12) 15.4% cumulative persisting annual savings for
11667	11667	12 the year ending December 31, 2029; and
11668	11668	13 (13) 16% cumulative persisting annual savings for the
11669	11669	14 year ending December 31, 2030.
11670	11670	15 No later than December 31, 2021, the Illinois Commerce
11671	11671	16 Commission shall establish additional cumulative persisting
11672	11672	17 annual savings goals for the years 2031 through 2035. No later
11673	11673	18 than December 31, 2024, the Illinois Commerce Commission shall
11674	11674	19 establish additional cumulative persisting annual savings
11675	11675	20 goals for the years 2036 through 2040. The Commission shall
11676	11676	21 also establish additional cumulative persisting annual savings
11677	11677	22 goals every 5 years thereafter to ensure that utilities always
11678	11678	23 have goals that extend at least 11 years into the future. The
11679	11679	24 cumulative persisting annual savings goals beyond the year
11680	11680	25 2030 shall increase by 0.6 percentage points per year, absent
11681	11681	26 a Commission decision to initiate a proceeding to consider
11682	11682
11683	11683
11684	11684
11685	11685
11686	11686
11687	11687	HB3779 - 325 - LRB104 11172 AAS 21254 b
11688	11688
11689	11689
11690	11690	HB3779- 326 -LRB104 11172 AAS 21254 b HB3779 - 326 - LRB104 11172 AAS 21254 b
11691	11691	HB3779 - 326 - LRB104 11172 AAS 21254 b
11692	11692	1 establishing goals that increase by more or less than that
11693	11693	2 amount. Such a proceeding must be conducted in accordance with
11694	11694	3 the procedures described in subsection (f) of this Section. If
11695	11695	4 such a proceeding is initiated, the cumulative persisting
11696	11696	5 annual savings goals established by the Commission through
11697	11697	6 that proceeding shall reflect the Commission's best estimate
11698	11698	7 of the maximum amount of additional savings that are forecast
11699	11699	8 to be cost-effectively achievable unless such best estimates
11700	11700	9 would result in goals that represent less than 0.4 percentage
11701	11701	10 point annual increases in total cumulative persisting annual
11702	11702	11 savings. The Commission may only establish goals that
11703	11703	12 represent less than 0.4 percentage point annual increases in
11704	11704	13 cumulative persisting annual savings if it can demonstrate,
11705	11705	14 based on clear and convincing evidence and through independent
11706	11706	15 analysis, that 0.4 percentage point increases are not
11707	11707	16 cost-effectively achievable. The Commission shall inform its
11708	11708	17 decision based on an energy efficiency potential study that
11709	11709	18 conforms to the requirements of this Section.
11710	11710	19 (b-16) In 2027 and each year thereafter, each electric
11711	11711	20 utility subject to this Section shall achieve incremental
11712	11712	21 annual savings equal to 2.00% of the utility's average annual
11713	11713	22 electricity sales, from 2021 through 2023, to customers other
11714	11714	23 than those that have opted out of subsections (a) through (j)
11715	11715	24 of this Section under paragraph (1) of subsection (l) of this
11716	11716	25 Section. In this Section, "incremental annual savings" means
11717	11717	26 the total electric savings from all measures installed in a
11718	11718
11719	11719
11720	11720
11721	11721
11722	11722
11723	11723	HB3779 - 326 - LRB104 11172 AAS 21254 b
11724	11724
11725	11725
11726	11726	HB3779- 327 -LRB104 11172 AAS 21254 b HB3779 - 327 - LRB104 11172 AAS 21254 b
11727	11727	HB3779 - 327 - LRB104 11172 AAS 21254 b
11728	11728	1 calendar year that will be realized within 12 months of each
11729	11729	2 measure's installation.
11730	11730	3 The 2.00% incremental annual savings requirement may be
11731	11731	4 reduced by 0.025 percentage points for every 1 percentage
11732	11732	5 point increase, above the 25% minimum specified in paragraph
11733	11733	6 (c) of this Section, in the portion of total efficiency
11734	11734	7 program spending that is on low-income or moderate income
11735	11735	8 efficiency programs. For the purposes of this section,
11736	11736	9 moderate income is defined as incomes between 80% of area
11737	11737	10 median income and 300% of the federal poverty limit. In no
11738	11738	11 event shall the incremental annual savings requirement be
11739	11739	12 reduced to a level less than 1.75%, even if the sum of
11740	11740	13 low-income spending and moderate income spending is greater
11741	11741	14 than 35% of total spending.
11742	11742	15 Each utility's incremental annual savings must be achieved
11743	11743	16 with an average savings life of at least 12 years. In no event
11744	11744	17 can more than one-fifth of the incremental annual savings
11745	11745	18 counted toward a utility's annual savings goal in any given
11746	11746	19 year be derived from efficiency measures with average savings
11747	11747	20 life of less than 5 years. Average savings life is defined as
11748	11748	21 the lifetime savings that would be realized as a result of a
11749	11749	22 utility's efficiency programs divided by the incremental
11750	11750	23 annual savings such programs produce. Average savings lives
11751	11751	24 may be shorter than the average operational lives of measures
11752	11752	25 installed if the measures do not produce savings in every year
11753	11753	26 in which they operate or if the savings that measures produce
11754	11754
11755	11755
11756	11756
11757	11757
11758	11758
11759	11759	HB3779 - 327 - LRB104 11172 AAS 21254 b
11760	11760
11761	11761
11762	11762	HB3779- 328 -LRB104 11172 AAS 21254 b HB3779 - 328 - LRB104 11172 AAS 21254 b
11763	11763	HB3779 - 328 - LRB104 11172 AAS 21254 b
11764	11764	1 decline during their operational lives.
11765	11765	2 (b-20) Each electric utility subject to this Section may
11766	11766	3 include cost-effective voltage optimization measures in its
11767	11767	4 plans submitted under subsections (f) and (g) of this Section,
11768	11768	5 and the costs incurred by a utility to implement the measures
11769	11769	6 under a Commission-approved plan shall be recovered under the
11770	11770	7 provisions of Article IX or Section 16-108.5 of this Act. For
11771	11771	8 purposes of this Section, the measure life of voltage
11772	11772	9 optimization measures shall be 15 years. The measure life
11773	11773	10 period is independent of the depreciation rate of the voltage
11774	11774	11 optimization assets deployed. Utilities may claim savings from
11775	11775	12 voltage optimization on circuits for more than 15 years if
11776	11776	13 they can demonstrate that they have made additional
11777	11777	14 investments necessary to enable voltage optimization savings
11778	11778	15 to continue beyond 15 years. Such demonstrations must be
11779	11779	16 subject to the review of independent evaluation.
11780	11780	17 Within 270 days after June 1, 2017 (the effective date of
11781	11781	18 Public Act 99-906), an electric utility that serves less than
11782	11782	19 3,000,000 retail customers but more than 500,000 retail
11783	11783	20 customers in the State shall file a plan with the Commission
11784	11784	21 that identifies the cost-effective voltage optimization
11785	11785	22 investment the electric utility plans to undertake through
11786	11786	23 December 31, 2024. The Commission, after notice and hearing,
11787	11787	24 shall approve or approve with modification the plan within 120
11788	11788	25 days after the plan's filing and, in the order approving or
11789	11789	26 approving with modification the plan, the Commission shall
11790	11790
11791	11791
11792	11792
11793	11793
11794	11794
11795	11795	HB3779 - 328 - LRB104 11172 AAS 21254 b
11796	11796
11797	11797
11798	11798	HB3779- 329 -LRB104 11172 AAS 21254 b HB3779 - 329 - LRB104 11172 AAS 21254 b
11799	11799	HB3779 - 329 - LRB104 11172 AAS 21254 b
11800	11800	1 adjust the applicable cumulative persisting annual savings
11801	11801	2 goals set forth in subsection (b-15) to reflect any amount of
11802	11802	3 cost-effective energy savings approved by the Commission that
11803	11803	4 is greater than or less than the following cumulative
11804	11804	5 persisting annual savings values attributable to voltage
11805	11805	6 optimization for the applicable year:
11806	11806	7 (1) 0.0% of cumulative persisting annual savings for
11807	11807	8 the year ending December 31, 2018;
11808	11808	9 (2) 0.17% of cumulative persisting annual savings for
11809	11809	10 the year ending December 31, 2019;
11810	11810	11 (3) 0.17% of cumulative persisting annual savings for
11811	11811	12 the year ending December 31, 2020;
11812	11812	13 (4) 0.33% of cumulative persisting annual savings for
11813	11813	14 the year ending December 31, 2021;
11814	11814	15 (5) 0.5% of cumulative persisting annual savings for
11815	11815	16 the year ending December 31, 2022;
11816	11816	17 (6) 0.67% of cumulative persisting annual savings for
11817	11817	18 the year ending December 31, 2023;
11818	11818	19 (7) 0.83% of cumulative persisting annual savings for
11819	11819	20 the year ending December 31, 2024; and
11820	11820	21 (8) 1.0% of cumulative persisting annual savings for
11821	11821	22 the year ending December 31, 2025 and all subsequent
11822	11822	23 years.
11823	11823	24 (b-25) In the event an electric utility jointly offers an
11824	11824	25 energy efficiency measure or program with a gas utility under
11825	11825	26 plans approved under this Section and Section 8-104 of this
11826	11826
11827	11827
11828	11828
11829	11829
11830	11830
11831	11831	HB3779 - 329 - LRB104 11172 AAS 21254 b
11832	11832
11833	11833
11834	11834	HB3779- 330 -LRB104 11172 AAS 21254 b HB3779 - 330 - LRB104 11172 AAS 21254 b
11835	11835	HB3779 - 330 - LRB104 11172 AAS 21254 b
11836	11836	1 Act, the electric utility may continue offering the program,
11837	11837	2 including the gas energy efficiency measures, in the event the
11838	11838	3 gas utility discontinues funding the program. In that event,
11839	11839	4 the energy savings value associated with such other fuels
11840	11840	5 shall be converted to electric energy savings on an equivalent
11841	11841	6 Btu basis for the premises. However, the electric utility
11842	11842	7 shall prioritize programs for low-income residential customers
11843	11843	8 to the extent practicable. An electric utility may recover the
11844	11844	9 costs of offering the gas energy efficiency measures under
11845	11845	10 this subsection (b-25).
11846	11846	11 For those energy efficiency measures or programs that save
11847	11847	12 both electricity and other fuels but are not jointly offered
11848	11848	13 with a gas utility under plans approved under this Section and
11849	11849	14 Section 8-104 or not offered with an affiliated gas utility
11850	11850	15 under paragraph (6) of subsection (f) of Section 8-104 of this
11851	11851	16 Act, the electric utility may count savings of fuels other
11852	11852	17 than electricity toward the achievement of its annual savings
11853	11853	18 goal, and the energy savings value associated with such other
11854	11854	19 fuels shall be converted to electric energy savings on an
11855	11855	20 equivalent Btu basis at the premises.
11856	11856	21 In no event shall more than 10% of each year's applicable
11857	11857	22 annual total savings requirement as defined in paragraph (7.5)
11858	11858	23 of subsection (g) of this Section, or more than 10% of each
11859	11859	24 year's incremental annual savings as defined in subsection
11860	11860	25 (b-16), be met through savings of fuels other than
11861	11861	26 electricity. If the weighted average total annual spending on
11862	11862
11863	11863
11864	11864
11865	11865
11866	11866
11867	11867	HB3779 - 330 - LRB104 11172 AAS 21254 b
11868	11868
11869	11869
11870	11870	HB3779- 331 -LRB104 11172 AAS 21254 b HB3779 - 331 - LRB104 11172 AAS 21254 b
11871	11871	HB3779 - 331 - LRB104 11172 AAS 21254 b
11872	11872	1 efficiency programs by natural gas utilities with service
11873	11873	2 territories that overlap with an electric utility exceeds $50
11874	11874	3 per residential customer served by the natural gas utilities,
11875	11875	4 the limit on the amount of efficiency savings of fuels other
11876	11876	5 than electricity that can be counted toward the electric
11877	11877	6 utility's incremental annual savings requirement as defined in
11878	11878	7 subsection (b-16) shall be reduced from 20% to 15%.
11879	11879	8 (b-27) Beginning in 2022, an electric utility may offer
11880	11880	9 and promote measures that electrify space heating, water
11881	11881	10 heating, cooling, drying, cooking, industrial processes, and
11882	11882	11 other building and industrial end uses that would otherwise be
11883	11883	12 served by combustion of fossil fuel at the premises, provided
11884	11884	13 that the electrification measures reduce total energy
11885	11885	14 consumption at the premises. The electric utility may count
11886	11886	15 the reduction in energy consumption at the premises toward
11887	11887	16 achievement of its annual savings goals. The reduction in
11888	11888	17 energy consumption at the premises shall be calculated as the
11889	11889	18 difference between: (A) the reduction in Btu consumption of
11890	11890	19 fossil fuels as a result of electrification, converted to
11891	11891	20 kilowatt-hour equivalents by dividing by 3,412 Btus per
11892	11892	21 kilowatt hour; and (B) the increase in kilowatt hours of
11893	11893	22 electricity consumption resulting from the displacement of
11894	11894	23 fossil fuel consumption as a result of electrification. An
11895	11895	24 electric utility may recover the costs of offering and
11896	11896	25 promoting electrification measures under this subsection
11897	11897	26 (b-27).
11898	11898
11899	11899
11900	11900
11901	11901
11902	11902
11903	11903	HB3779 - 331 - LRB104 11172 AAS 21254 b
11904	11904
11905	11905
11906	11906	HB3779- 332 -LRB104 11172 AAS 21254 b HB3779 - 332 - LRB104 11172 AAS 21254 b
11907	11907	HB3779 - 332 - LRB104 11172 AAS 21254 b
11908	11908	1 At least 33% of all such costs must be for supporting
11909	11909	2 installation of electrification measures through programs
11910	11910	3 exclusively targeted to low-income households. This 33%
11911	11911	4 requirement may be reduced if the utility can demonstrate that
11912	11912	5 it is not possible to achieve that level of low-income
11913	11913	6 electrification spending, while supporting programs for
11914	11914	7 non-low-income residential and business electrification,
11915	11915	8 because of limitations regarding the number of low-income
11916	11916	9 households in its service territory that would be able to meet
11917	11917	10 program eligibility requirements set forth in the multi-year
11918	11918	11 energy efficiency plan. If the 33% low-income electrification
11919	11919	12 spending requirement is reduced, the utility must prioritize
11920	11920	13 support of low-income electrification in housing that meets
11921	11921	14 program eligibility requirements over electrification spending
11922	11922	15 on non-low-income residential or business customers.
11923	11923	16 The ratio of spending on electrification measures targeted
11924	11924	17 to low-income, multifamily buildings to spending on
11925	11925	18 electrification measures targeted to low-income, single-family
11926	11926	19 buildings shall be designed to achieve levels of
11927	11927	20 electrification savings from each building type that are
11928	11928	21 approximately proportional to the magnitude of cost-effective
11929	11929	22 electrification savings potential in each building type.
11930	11930	23 In no event shall electrification savings counted toward
11931	11931	24 each year's applicable annual total savings requirement, as
11932	11932	25 defined in paragraph (7.5) of subsection (g) of this Section,
11933	11933	26 or counted toward each year's incremental annual savings, as
11934	11934
11935	11935
11936	11936
11937	11937
11938	11938
11939	11939	HB3779 - 332 - LRB104 11172 AAS 21254 b
11940	11940
11941	11941
11942	11942	HB3779- 333 -LRB104 11172 AAS 21254 b HB3779 - 333 - LRB104 11172 AAS 21254 b
11943	11943	HB3779 - 333 - LRB104 11172 AAS 21254 b
11944	11944	1 defined in paragraph (b-16) of this Section, be greater than:
11945	11945	2 (1) 5% per year for each year from 2022 through 2025;
11946	11946	3 (1.5) 10% per year for 2026; and
11947	11947	4 (2) 15% per year for 2027 and all subsequent years.
11948	11948	5 10% per year for each year from 2026 through 2029; and
11949	11949	6 (3) 15% per year for 2030 and all subsequent years.
11950	11950	7 In addition, a minimum of 25% of all electrification savings
11951	11951	8 counted toward a utility's applicable annual total savings
11952	11952	9 requirement must be from electrification of end uses in
11953	11953	10 low-income housing. The limitations on electrification savings
11954	11954	11 that may be counted toward a utility's annual savings goals
11955	11955	12 are separate from and in addition to the subsection (b-25)
11956	11956	13 limitations governing the counting of the other fuel savings
11957	11957	14 resulting from efficiency measures and programs.
11958	11958	15 As part of the annual informational filing to the
11959	11959	16 Commission that is required under paragraph (9) of subsection
11960	11960	17 (g) of this Section, each utility shall identify the specific
11961	11961	18 electrification measures offered under this subsection (b-27);
11962	11962	19 the quantity of each electrification measure that was
11963	11963	20 installed by its customers; the average total cost, average
11964	11964	21 utility cost, average reduction in fossil fuel consumption,
11965	11965	22 and average increase in electricity consumption associated
11966	11966	23 with each electrification measure; the portion of
11967	11967	24 installations of each electrification measure that were in
11968	11968	25 low-income single-family housing, low-income multifamily
11969	11969	26 housing, non-low-income single-family housing, non-low-income
11970	11970
11971	11971
11972	11972
11973	11973
11974	11974
11975	11975	HB3779 - 333 - LRB104 11172 AAS 21254 b
11976	11976
11977	11977
11978	11978	HB3779- 334 -LRB104 11172 AAS 21254 b HB3779 - 334 - LRB104 11172 AAS 21254 b
11979	11979	HB3779 - 334 - LRB104 11172 AAS 21254 b
11980	11980	1 multifamily housing, commercial buildings, and industrial
11981	11981	2 facilities; and the quantity of savings associated with each
11982	11982	3 measure category in each customer category that are being
11983	11983	4 counted toward the utility's applicable annual total savings
11984	11984	5 requirement or the utility's incremental annual savings as
11985	11985	6 defined in subsection (b-16). Prior to installing an
11986	11986	7 electrification measure, the utility shall provide a customer
11987	11987	8 with an estimate of the impact of the new measure on the
11988	11988	9 customer's average monthly electric bill and total annual
11989	11989	10 energy expenses.
11990	11990	11 (c) Electric utilities shall be responsible for overseeing
11991	11991	12 the design, development, and filing of energy efficiency plans
11992	11992	13 with the Commission and may, as part of that implementation,
11993	11993	14 outsource various aspects of program development and
11994	11994	15 implementation. A minimum of 10%, for electric utilities that
11995	11995	16 serve more than 3,000,000 retail customers in the State, and a
11996	11996	17 minimum of 7%, for electric utilities that serve less than
11997	11997	18 3,000,000 retail customers but more than 500,000 retail
11998	11998	19 customers in the State, of the utility's entire portfolio
11999	11999	20 funding level for a given year shall be used to procure
12000	12000	21 cost-effective energy efficiency measures from units of local
12001	12001	22 government, municipal corporations, school districts, public
12002	12002	23 housing, and community college districts, provided that a
12003	12003	24 minimum percentage of available funds shall be used to procure
12004	12004	25 energy efficiency from public housing, which percentage shall
12005	12005	26 be equal to public housing's share of public building energy
12006	12006
12007	12007
12008	12008
12009	12009
12010	12010
12011	12011	HB3779 - 334 - LRB104 11172 AAS 21254 b
12012	12012
12013	12013
12014	12014	HB3779- 335 -LRB104 11172 AAS 21254 b HB3779 - 335 - LRB104 11172 AAS 21254 b
12015	12015	HB3779 - 335 - LRB104 11172 AAS 21254 b
12016	12016	1 consumption.
12017	12017	2 The utilities shall also implement energy efficiency
12018	12018	3 measures targeted at low-income households, which, for
12019	12019	4 purposes of this Section, shall be defined as households at or
12020	12020	5 below 80% of area median income, and expenditures to implement
12021	12021	6 the measures shall be no less than 25% of total energy
12022	12022	7 efficiency program spending approved by the Commission
12023	12023	8 pursuant to review of plans filed under paragraph (f) of this
12024	12024	9 Section $40,000,000 per year for electric utilities that serve
12025	12025	10 more than 3,000,000 retail customers in the State and no less
12026	12026	11 than $13,000,000 per year for electric utilities that serve
12027	12027	12 less than 3,000,000 retail customers but more than 500,000
12028	12028	13 retail customers in the State. The ratio of spending on
12029	12029	14 efficiency programs targeted at low-income multifamily
12030	12030	15 buildings to spending on efficiency programs targeted at
12031	12031	16 low-income single-family buildings shall be designed to
12032	12032	17 achieve levels of savings from each building type that are
12033	12033	18 approximately proportional to the magnitude of cost-effective
12034	12034	19 lifetime savings potential in each building type. Investment
12035	12035	20 in low-income whole-building weatherization programs shall
12036	12036	21 constitute a minimum of 80% of a utility's total budget
12037	12037	22 specifically dedicated to serving low-income customers.
12038	12038	23 The utilities shall work to bundle low-income energy
12039	12039	24 efficiency offerings with other programs that serve low-income
12040	12040	25 households to maximize the benefits going to these households.
12041	12041	26 The utilities shall market and implement low-income energy
12042	12042
12043	12043
12044	12044
12045	12045
12046	12046
12047	12047	HB3779 - 335 - LRB104 11172 AAS 21254 b
12048	12048
12049	12049
12050	12050	HB3779- 336 -LRB104 11172 AAS 21254 b HB3779 - 336 - LRB104 11172 AAS 21254 b
12051	12051	HB3779 - 336 - LRB104 11172 AAS 21254 b
12052	12052	1 efficiency programs in coordination with low-income assistance
12053	12053	2 programs, the Illinois Solar for All Program, and
12054	12054	3 weatherization whenever practicable. The program implementer
12055	12055	4 shall walk the customer through the enrollment process for any
12056	12056	5 programs for which the customer is eligible. The utilities
12057	12057	6 shall also pilot targeting customers with high arrearages,
12058	12058	7 high energy intensity (ratio of energy usage divided by home
12059	12059	8 or unit square footage), or energy assistance programs with
12060	12060	9 energy efficiency offerings, and then track reduction in
12061	12061	10 arrearages as a result of the targeting. This targeting and
12062	12062	11 bundling of low-income energy programs shall be offered to
12063	12063	12 both low-income single-family and multifamily customers
12064	12064	13 (owners and residents).
12065	12065	14 The utilities shall invest in health and safety measures
12066	12066	15 appropriate and necessary for comprehensively weatherizing a
12067	12067	16 home or multifamily building, and shall implement a health and
12068	12068	17 safety fund of at least 15% of the total income-qualified
12069	12069	18 weatherization budget that shall be used for the purpose of
12070	12070	19 making grants for technical assistance, construction,
12071	12071	20 reconstruction, improvement, or repair of buildings to
12072	12072	21 facilitate their participation in the energy efficiency
12073	12073	22 programs targeted at low-income single-family and multifamily
12074	12074	23 households. These funds may also be used for the purpose of
12075	12075	24 making grants for technical assistance, construction,
12076	12076	25 reconstruction, improvement, or repair of the following
12077	12077	26 buildings to facilitate their participation in the energy
12078	12078
12079	12079
12080	12080
12081	12081
12082	12082
12083	12083	HB3779 - 336 - LRB104 11172 AAS 21254 b
12084	12084
12085	12085
12086	12086	HB3779- 337 -LRB104 11172 AAS 21254 b HB3779 - 337 - LRB104 11172 AAS 21254 b
12087	12087	HB3779 - 337 - LRB104 11172 AAS 21254 b
12088	12088	1 efficiency programs created by this Section: (1) buildings
12089	12089	2 that are owned or operated by registered 501(c)(3) public
12090	12090	3 charities; and (2) day care centers, day care homes, or group
12091	12091	4 day care homes, as defined under 89 Ill. Adm. Code Part 406,
12092	12092	5 407, or 408, respectively.
12093	12093	6 Each electric utility shall assess opportunities to
12094	12094	7 implement cost-effective energy efficiency measures and
12095	12095	8 programs through a public housing authority or authorities
12096	12096	9 located in its service territory. If such opportunities are
12097	12097	10 identified, the utility shall propose such measures and
12098	12098	11 programs to address the opportunities. Expenditures to address
12099	12099	12 such opportunities shall be credited toward the minimum
12100	12100	13 procurement and expenditure requirements set forth in this
12101	12101	14 subsection (c).
12102	12102	15 Implementation of energy efficiency measures and programs
12103	12103	16 targeted at low-income households should be contracted, when
12104	12104	17 it is practicable, to independent third parties that have
12105	12105	18 demonstrated capabilities to serve such households, with a
12106	12106	19 preference for not-for-profit entities and government agencies
12107	12107	20 that have existing relationships with or experience serving
12108	12108	21 low-income communities in the State.
12109	12109	22 Each electric utility shall develop and implement
12110	12110	23 reporting procedures that address and assist in determining
12111	12111	24 the amount of energy savings that can be applied to the
12112	12112	25 low-income procurement and expenditure requirements set forth
12113	12113	26 in this subsection (c). Each electric utility shall also track
12114	12114
12115	12115
12116	12116
12117	12117
12118	12118
12119	12119	HB3779 - 337 - LRB104 11172 AAS 21254 b
12120	12120
12121	12121
12122	12122	HB3779- 338 -LRB104 11172 AAS 21254 b HB3779 - 338 - LRB104 11172 AAS 21254 b
12123	12123	HB3779 - 338 - LRB104 11172 AAS 21254 b
12124	12124	1 the types and quantities or volumes of insulation and air
12125	12125	2 sealing materials, and their associated energy saving
12126	12126	3 benefits, installed in energy efficiency programs targeted at
12127	12127	4 low-income single-family and multifamily households.
12128	12128	5 The electric utilities shall participate in a low-income
12129	12129	6 energy efficiency accountability committee ("the committee"),
12130	12130	7 which will directly inform the design, implementation, and
12131	12131	8 evaluation of the low-income and public-housing energy
12132	12132	9 efficiency programs. The committee shall be comprised of the
12133	12133	10 electric utilities subject to the requirements of this
12134	12134	11 Section, the gas utilities subject to the requirements of
12135	12135	12 Section 8-104 of this Act, the utilities' low-income energy
12136	12136	13 efficiency implementation contractors, nonprofit
12137	12137	14 organizations, community action agencies, advocacy groups,
12138	12138	15 State and local governmental agencies, public-housing
12139	12139	16 organizations, and representatives of community-based
12140	12140	17 organizations, especially those living in or working with
12141	12141	18 environmental justice communities and BIPOC communities. The
12142	12142	19 committee shall be composed of 2 geographically differentiated
12143	12143	20 subcommittees: one for stakeholders in northern Illinois and
12144	12144	21 one for stakeholders in central and southern Illinois. The
12145	12145	22 subcommittees shall meet together at least twice per year.
12146	12146	23 There shall be one statewide leadership committee led by
12147	12147	24 and composed of community-based organizations that are
12148	12148	25 representative of BIPOC and environmental justice communities
12149	12149	26 and that includes equitable representation from BIPOC
12150	12150
12151	12151
12152	12152
12153	12153
12154	12154
12155	12155	HB3779 - 338 - LRB104 11172 AAS 21254 b
12156	12156
12157	12157
12158	12158	HB3779- 339 -LRB104 11172 AAS 21254 b HB3779 - 339 - LRB104 11172 AAS 21254 b
12159	12159	HB3779 - 339 - LRB104 11172 AAS 21254 b
12160	12160	1 communities. The leadership committee shall be composed of an
12161	12161	2 equal number of representatives from the 2 subcommittees. The
12162	12162	3 subcommittees shall address specific programs and issues, with
12163	12163	4 the leadership committee convening targeted workgroups as
12164	12164	5 needed. The leadership committee may elect to work with an
12165	12165	6 independent facilitator to solicit and organize feedback,
12166	12166	7 recommendations and meeting participation from a wide variety
12167	12167	8 of community-based stakeholders. If a facilitator is used,
12168	12168	9 they shall be fair and responsive to the needs of all
12169	12169	10 stakeholders involved in the committee.
12170	12170	11 All committee meetings must be accessible, with rotating
12171	12171	12 locations if meetings are held in-person, virtual
12172	12172	13 participation options, and materials and agendas circulated in
12173	12173	14 advance.
12174	12174	15 There shall also be opportunities for direct input by
12175	12175	16 committee members outside of committee meetings, such as via
12176	12176	17 individual meetings, surveys, emails and calls, to ensure
12177	12177	18 robust participation by stakeholders with limited capacity and
12178	12178	19 ability to attend committee meetings. Committee meetings shall
12179	12179	20 emphasize opportunities to bundle and coordinate delivery of
12180	12180	21 low-income energy efficiency with other programs that serve
12181	12181	22 low-income communities, such as the Illinois Solar for All
12182	12182	23 Program and bill payment assistance programs. Meetings shall
12183	12183	24 include educational opportunities for stakeholders to learn
12184	12184	25 more about these additional offerings, and the committee shall
12185	12185	26 assist in figuring out the best methods for coordinated
12186	12186
12187	12187
12188	12188
12189	12189
12190	12190
12191	12191	HB3779 - 339 - LRB104 11172 AAS 21254 b
12192	12192
12193	12193
12194	12194	HB3779- 340 -LRB104 11172 AAS 21254 b HB3779 - 340 - LRB104 11172 AAS 21254 b
12195	12195	HB3779 - 340 - LRB104 11172 AAS 21254 b
12196	12196	1 delivery and implementation of offerings when serving
12197	12197	2 low-income communities. The committee shall directly and
12198	12198	3 equitably influence and inform utility low-income and
12199	12199	4 public-housing energy efficiency programs and priorities.
12200	12200	5 Participating utilities shall implement recommendations from
12201	12201	6 the committee whenever possible.
12202	12202	7 Participating utilities shall track and report how input
12203	12203	8 from the committee has led to new approaches and changes in
12204	12204	9 their energy efficiency portfolios. This reporting shall occur
12205	12205	10 at committee meetings and in quarterly energy efficiency
12206	12206	11 reports to the Stakeholder Advisory Group and Illinois
12207	12207	12 Commerce Commission, and other relevant reporting mechanisms.
12208	12208	13 Participating utilities shall also report on relevant equity
12209	12209	14 data and metrics requested by the committee, such as energy
12210	12210	15 burden data, geographic, racial, and other relevant
12211	12211	16 demographic data on where programs are being delivered and
12212	12212	17 what populations programs are serving.
12213	12213	18 The Illinois Commerce Commission shall oversee and have
12214	12214	19 relevant staff participate in the committee. The committee
12215	12215	20 shall have a budget of 0.25% of each utility's entire
12216	12216	21 efficiency portfolio funding for a given year. The budget
12217	12217	22 shall be overseen by the Commission. The budget shall be used
12218	12218	23 to provide grants for community-based organizations serving on
12219	12219	24 the leadership committee, stipends for community-based
12220	12220	25 organizations participating in the committee, grants for
12221	12221	26 community-based organizations to do energy efficiency outreach
12222	12222
12223	12223
12224	12224
12225	12225
12226	12226
12227	12227	HB3779 - 340 - LRB104 11172 AAS 21254 b
12228	12228
12229	12229
12230	12230	HB3779- 341 -LRB104 11172 AAS 21254 b HB3779 - 341 - LRB104 11172 AAS 21254 b
12231	12231	HB3779 - 341 - LRB104 11172 AAS 21254 b
12232	12232	1 and education, and relevant meeting needs as determined by the
12233	12233	2 leadership committee. The education and outreach shall
12234	12234	3 include, but is not limited to, basic energy efficiency
12235	12235	4 education, information about low-income energy efficiency
12236	12236	5 programs, and information on the committee's purpose,
12237	12237	6 structure, and activities.
12238	12238	7 (d) Notwithstanding any other provision of law to the
12239	12239	8 contrary, a utility providing approved energy efficiency
12240	12240	9 measures and, if applicable, demand-response measures in the
12241	12241	10 State shall be permitted to recover all reasonable and
12242	12242	11 prudently incurred costs of those measures from all retail
12243	12243	12 customers, except as provided in subsection (l) of this
12244	12244	13 Section, as follows, provided that nothing in this subsection
12245	12245	14 (d) permits the double recovery of such costs from customers:
12246	12246	15 (1) The utility may recover its costs through an
12247	12247	16 automatic adjustment clause tariff filed with and approved
12248	12248	17 by the Commission. The tariff shall be established outside
12249	12249	18 the context of a general rate case. Each year the
12250	12250	19 Commission shall initiate a review to reconcile any
12251	12251	20 amounts collected with the actual costs and to determine
12252	12252	21 the required adjustment to the annual tariff factor to
12253	12253	22 match annual expenditures. To enable the financing of the
12254	12254	23 incremental capital expenditures, including regulatory
12255	12255	24 assets, for electric utilities that serve less than
12256	12256	25 3,000,000 retail customers but more than 500,000 retail
12257	12257	26 customers in the State, the utility's actual year-end
12258	12258
12259	12259
12260	12260
12261	12261
12262	12262
12263	12263	HB3779 - 341 - LRB104 11172 AAS 21254 b
12264	12264
12265	12265
12266	12266	HB3779- 342 -LRB104 11172 AAS 21254 b HB3779 - 342 - LRB104 11172 AAS 21254 b
12267	12267	HB3779 - 342 - LRB104 11172 AAS 21254 b
12268	12268	1 capital structure that includes a common equity ratio,
12269	12269	2 excluding goodwill, of up to and including 50% of the
12270	12270	3 total capital structure shall be deemed reasonable and
12271	12271	4 used to set rates.
12272	12272	5 (2) A utility may recover its costs through an energy
12273	12273	6 efficiency formula rate approved by the Commission under a
12274	12274	7 filing under subsections (f) and (g) of this Section,
12275	12275	8 which shall specify the cost components that form the
12276	12276	9 basis of the rate charged to customers with sufficient
12277	12277	10 specificity to operate in a standardized manner and be
12278	12278	11 updated annually with transparent information that
12279	12279	12 reflects the utility's actual costs to be recovered during
12280	12280	13 the applicable rate year, which is the period beginning
12281	12281	14 with the first billing day of January and extending
12282	12282	15 through the last billing day of the following December.
12283	12283	16 The energy efficiency formula rate shall be implemented
12284	12284	17 through a tariff filed with the Commission under
12285	12285	18 subsections (f) and (g) of this Section that is consistent
12286	12286	19 with the provisions of this paragraph (2) and that shall
12287	12287	20 be applicable to all delivery services customers. The
12288	12288	21 Commission shall conduct an investigation of the tariff in
12289	12289	22 a manner consistent with the provisions of this paragraph
12290	12290	23 (2), subsections (f) and (g) of this Section, and the
12291	12291	24 provisions of Article IX of this Act to the extent they do
12292	12292	25 not conflict with this paragraph (2). The energy
12293	12293	26 efficiency formula rate approved by the Commission shall
12294	12294
12295	12295
12296	12296
12297	12297
12298	12298
12299	12299	HB3779 - 342 - LRB104 11172 AAS 21254 b
12300	12300
12301	12301
12302	12302	HB3779- 343 -LRB104 11172 AAS 21254 b HB3779 - 343 - LRB104 11172 AAS 21254 b
12303	12303	HB3779 - 343 - LRB104 11172 AAS 21254 b
12304	12304	1 remain in effect at the discretion of the utility and
12305	12305	2 shall do the following:
12306	12306	3 (A) Provide for the recovery of the utility's
12307	12307	4 actual costs incurred under this Section that are
12308	12308	5 prudently incurred and reasonable in amount consistent
12309	12309	6 with Commission practice and law. The sole fact that a
12310	12310	7 cost differs from that incurred in a prior calendar
12311	12311	8 year or that an investment is different from that made
12312	12312	9 in a prior calendar year shall not imply the
12313	12313	10 imprudence or unreasonableness of that cost or
12314	12314	11 investment.
12315	12315	12 (B) Reflect the utility's actual year-end capital
12316	12316	13 structure for the applicable calendar year, excluding
12317	12317	14 goodwill, subject to a determination of prudence and
12318	12318	15 reasonableness consistent with Commission practice and
12319	12319	16 law. To enable the financing of the incremental
12320	12320	17 capital expenditures, including regulatory assets, for
12321	12321	18 electric utilities that serve less than 3,000,000
12322	12322	19 retail customers but more than 500,000 retail
12323	12323	20 customers in the State, a participating electric
12324	12324	21 utility's actual year-end capital structure that
12325	12325	22 includes a common equity ratio, excluding goodwill, of
12326	12326	23 up to and including 50% of the total capital structure
12327	12327	24 shall be deemed reasonable and used to set rates.
12328	12328	25 (C) For years through 2025, include Include a cost
12329	12329	26 of equity, which shall be calculated as the sum of the
12330	12330
12331	12331
12332	12332
12333	12333
12334	12334
12335	12335	HB3779 - 343 - LRB104 11172 AAS 21254 b
12336	12336
12337	12337
12338	12338	HB3779- 344 -LRB104 11172 AAS 21254 b HB3779 - 344 - LRB104 11172 AAS 21254 b
12339	12339	HB3779 - 344 - LRB104 11172 AAS 21254 b
12340	12340	1 following:
12341	12341	2 (i) the average for the applicable calendar
12342	12342	3 year of the monthly average yields of 30-year U.S.
12343	12343	4 Treasury bonds published by the Board of Governors
12344	12344	5 of the Federal Reserve System in its weekly H.15
12345	12345	6 Statistical Release or successor publication; and
12346	12346	7 (ii) 580 basis points.
12347	12347	8 At such time as the Board of Governors of the
12348	12348	9 Federal Reserve System ceases to include the monthly
12349	12349	10 average yields of 30-year U.S. Treasury bonds in its
12350	12350	11 weekly H.15 Statistical Release or successor
12351	12351	12 publication, the monthly average yields of the U.S.
12352	12352	13 Treasury bonds then having the longest duration
12353	12353	14 published by the Board of Governors in its weekly H.15
12354	12354	15 Statistical Release or successor publication shall
12355	12355	16 instead be used for purposes of this paragraph (2).
12356	12356	17 For 2026 and subsequent years, include a cost of
12357	12357	18 equity equal to the value most recently approved by
12358	12358	19 the Commission for the utility's capital investments
12359	12359	20 in its distribution system.
12360	12360	21 (D) Permit and set forth protocols, subject to a
12361	12361	22 determination of prudence and reasonableness
12362	12362	23 consistent with Commission practice and law, for the
12363	12363	24 following:
12364	12364	25 (i) recovery of incentive compensation expense
12365	12365	26 that is based on the achievement of operational
12366	12366
12367	12367
12368	12368
12369	12369
12370	12370
12371	12371	HB3779 - 344 - LRB104 11172 AAS 21254 b
12372	12372
12373	12373
12374	12374	HB3779- 345 -LRB104 11172 AAS 21254 b HB3779 - 345 - LRB104 11172 AAS 21254 b
12375	12375	HB3779 - 345 - LRB104 11172 AAS 21254 b
12376	12376	1 metrics, including metrics related to budget
12377	12377	2 controls, outage duration and frequency, safety,
12378	12378	3 customer service, efficiency and productivity, and
12379	12379	4 environmental compliance; however, this protocol
12380	12380	5 shall not apply if such expense related to costs
12381	12381	6 incurred under this Section is recovered under
12382	12382	7 Article IX or Section 16-108.5 of this Act;
12383	12383	8 incentive compensation expense that is based on
12384	12384	9 net income or an affiliate's earnings per share
12385	12385	10 shall not be recoverable under the energy
12386	12386	11 efficiency formula rate;
12387	12387	12 (ii) recovery of pension and other
12388	12388	13 post-employment benefits expense, provided that
12389	12389	14 such costs are supported by an actuarial study;
12390	12390	15 however, this protocol shall not apply if such
12391	12391	16 expense related to costs incurred under this
12392	12392	17 Section is recovered under Article IX or Section
12393	12393	18 16-108.5 of this Act;
12394	12394	19 (iii) recovery of existing regulatory assets
12395	12395	20 over the periods previously authorized by the
12396	12396	21 Commission;
12397	12397	22 (iv) as described in subsection (e),
12398	12398	23 amortization of costs incurred under this Section;
12399	12399	24 and
12400	12400	25 (v) projected, weather normalized billing
12401	12401	26 determinants for the applicable rate year.
12402	12402
12403	12403
12404	12404
12405	12405
12406	12406
12407	12407	HB3779 - 345 - LRB104 11172 AAS 21254 b
12408	12408
12409	12409
12410	12410	HB3779- 346 -LRB104 11172 AAS 21254 b HB3779 - 346 - LRB104 11172 AAS 21254 b
12411	12411	HB3779 - 346 - LRB104 11172 AAS 21254 b
12412	12412	1 (E) Provide for an annual reconciliation, as
12413	12413	2 described in paragraph (3) of this subsection (d),
12414	12414	3 less any deferred taxes related to the reconciliation,
12415	12415	4 with interest at an annual rate of return equal to the
12416	12416	5 utility's weighted average cost of capital, including
12417	12417	6 a revenue conversion factor calculated to recover or
12418	12418	7 refund all additional income taxes that may be payable
12419	12419	8 or receivable as a result of that return, of the energy
12420	12420	9 efficiency revenue requirement reflected in rates for
12421	12421	10 each calendar year, beginning with the calendar year
12422	12422	11 in which the utility files its energy efficiency
12423	12423	12 formula rate tariff under this paragraph (2), with
12424	12424	13 what the revenue requirement would have been had the
12425	12425	14 actual cost information for the applicable calendar
12426	12426	15 year been available at the filing date.
12427	12427	16 The utility shall file, together with its tariff, the
12428	12428	17 projected costs to be incurred by the utility during the
12429	12429	18 rate year under the utility's multi-year plan approved
12430	12430	19 under subsections (f) and (g) of this Section, including,
12431	12431	20 but not limited to, the projected capital investment costs
12432	12432	21 and projected regulatory asset balances with
12433	12433	22 correspondingly updated depreciation and amortization
12434	12434	23 reserves and expense, that shall populate the energy
12435	12435	24 efficiency formula rate and set the initial rates under
12436	12436	25 the formula.
12437	12437	26 The Commission shall review the proposed tariff in
12438	12438
12439	12439
12440	12440
12441	12441
12442	12442
12443	12443	HB3779 - 346 - LRB104 11172 AAS 21254 b
12444	12444
12445	12445
12446	12446	HB3779- 347 -LRB104 11172 AAS 21254 b HB3779 - 347 - LRB104 11172 AAS 21254 b
12447	12447	HB3779 - 347 - LRB104 11172 AAS 21254 b
12448	12448	1 conjunction with its review of a proposed multi-year plan,
12449	12449	2 as specified in paragraph (5) of subsection (g) of this
12450	12450	3 Section. The review shall be based on the same evidentiary
12451	12451	4 standards, including, but not limited to, those concerning
12452	12452	5 the prudence and reasonableness of the costs incurred by
12453	12453	6 the utility, the Commission applies in a hearing to review
12454	12454	7 a filing for a general increase in rates under Article IX
12455	12455	8 of this Act. The initial rates shall take effect beginning
12456	12456	9 with the January monthly billing period following the
12457	12457	10 Commission's approval.
12458	12458	11 The tariff's rate design and cost allocation across
12459	12459	12 customer classes shall be consistent with the utility's
12460	12460	13 automatic adjustment clause tariff in effect on June 1,
12461	12461	14 2017 (the effective date of Public Act 99-906); however,
12462	12462	15 the Commission may revise the tariff's rate design and
12463	12463	16 cost allocation in subsequent proceedings under paragraph
12464	12464	17 (3) of this subsection (d).
12465	12465	18 If the energy efficiency formula rate is terminated,
12466	12466	19 the then current rates shall remain in effect until such
12467	12467	20 time as the energy efficiency costs are incorporated into
12468	12468	21 new rates that are set under this subsection (d) or
12469	12469	22 Article IX of this Act, subject to retroactive rate
12470	12470	23 adjustment, with interest, to reconcile rates charged with
12471	12471	24 actual costs.
12472	12472	25 (3) The provisions of this paragraph (3) shall only
12473	12473	26 apply to an electric utility that has elected to file an
12474	12474
12475	12475
12476	12476
12477	12477
12478	12478
12479	12479	HB3779 - 347 - LRB104 11172 AAS 21254 b
12480	12480
12481	12481
12482	12482	HB3779- 348 -LRB104 11172 AAS 21254 b HB3779 - 348 - LRB104 11172 AAS 21254 b
12483	12483	HB3779 - 348 - LRB104 11172 AAS 21254 b
12484	12484	1 energy efficiency formula rate under paragraph (2) of this
12485	12485	2 subsection (d). Subsequent to the Commission's issuance of
12486	12486	3 an order approving the utility's energy efficiency formula
12487	12487	4 rate structure and protocols, and initial rates under
12488	12488	5 paragraph (2) of this subsection (d), the utility shall
12489	12489	6 file, on or before June 1 of each year, with the Chief
12490	12490	7 Clerk of the Commission its updated cost inputs to the
12491	12491	8 energy efficiency formula rate for the applicable rate
12492	12492	9 year and the corresponding new charges, as well as the
12493	12493	10 information described in paragraph (9) of subsection (g)
12494	12494	11 of this Section. Each such filing shall conform to the
12495	12495	12 following requirements and include the following
12496	12496	13 information:
12497	12497	14 (A) The inputs to the energy efficiency formula
12498	12498	15 rate for the applicable rate year shall be based on the
12499	12499	16 projected costs to be incurred by the utility during
12500	12500	17 the rate year under the utility's multi-year plan
12501	12501	18 approved under subsections (f) and (g) of this
12502	12502	19 Section, including, but not limited to, projected
12503	12503	20 capital investment costs and projected regulatory
12504	12504	21 asset balances with correspondingly updated
12505	12505	22 depreciation and amortization reserves and expense.
12506	12506	23 The filing shall also include a reconciliation of the
12507	12507	24 energy efficiency revenue requirement that was in
12508	12508	25 effect for the prior rate year (as set by the cost
12509	12509	26 inputs for the prior rate year) with the actual
12510	12510
12511	12511
12512	12512
12513	12513
12514	12514
12515	12515	HB3779 - 348 - LRB104 11172 AAS 21254 b
12516	12516
12517	12517
12518	12518	HB3779- 349 -LRB104 11172 AAS 21254 b HB3779 - 349 - LRB104 11172 AAS 21254 b
12519	12519	HB3779 - 349 - LRB104 11172 AAS 21254 b
12520	12520	1 revenue requirement for the prior rate year
12521	12521	2 (determined using a year-end rate base) that uses
12522	12522	3 amounts reflected in the applicable FERC Form 1 that
12523	12523	4 reports the actual costs for the prior rate year. Any
12524	12524	5 over-collection or under-collection indicated by such
12525	12525	6 reconciliation shall be reflected as a credit against,
12526	12526	7 or recovered as an additional charge to, respectively,
12527	12527	8 with interest calculated at a rate equal to the
12528	12528	9 utility's weighted average cost of capital approved by
12529	12529	10 the Commission for the prior rate year, the charges
12530	12530	11 for the applicable rate year. Such over-collection or
12531	12531	12 under-collection shall be adjusted to remove any
12532	12532	13 deferred taxes related to the reconciliation, for
12533	12533	14 purposes of calculating interest at an annual rate of
12534	12534	15 return equal to the utility's weighted average cost of
12535	12535	16 capital approved by the Commission for the prior rate
12536	12536	17 year, including a revenue conversion factor calculated
12537	12537	18 to recover or refund all additional income taxes that
12538	12538	19 may be payable or receivable as a result of that
12539	12539	20 return. Each reconciliation shall be certified by the
12540	12540	21 participating utility in the same manner that FERC
12541	12541	22 Form 1 is certified. The filing shall also include the
12542	12542	23 charge or credit, if any, resulting from the
12543	12543	24 calculation required by subparagraph (E) of paragraph
12544	12544	25 (2) of this subsection (d).
12545	12545	26 Notwithstanding any other provision of law to the
12546	12546
12547	12547
12548	12548
12549	12549
12550	12550
12551	12551	HB3779 - 349 - LRB104 11172 AAS 21254 b
12552	12552
12553	12553
12554	12554	HB3779- 350 -LRB104 11172 AAS 21254 b HB3779 - 350 - LRB104 11172 AAS 21254 b
12555	12555	HB3779 - 350 - LRB104 11172 AAS 21254 b
12556	12556	1 contrary, the intent of the reconciliation is to
12557	12557	2 ultimately reconcile both the revenue requirement
12558	12558	3 reflected in rates for each calendar year, beginning
12559	12559	4 with the calendar year in which the utility files its
12560	12560	5 energy efficiency formula rate tariff under paragraph
12561	12561	6 (2) of this subsection (d), with what the revenue
12562	12562	7 requirement determined using a year-end rate base for
12563	12563	8 the applicable calendar year would have been had the
12564	12564	9 actual cost information for the applicable calendar
12565	12565	10 year been available at the filing date.
12566	12566	11 For purposes of this Section, "FERC Form 1" means
12567	12567	12 the Annual Report of Major Electric Utilities,
12568	12568	13 Licensees and Others that electric utilities are
12569	12569	14 required to file with the Federal Energy Regulatory
12570	12570	15 Commission under the Federal Power Act, Sections 3,
12571	12571	16 4(a), 304 and 209, modified as necessary to be
12572	12572	17 consistent with 83 Ill. Adm. Code Part 415 as of May 1,
12573	12573	18 2011. Nothing in this Section is intended to allow
12574	12574	19 costs that are not otherwise recoverable to be
12575	12575	20 recoverable by virtue of inclusion in FERC Form 1.
12576	12576	21 (B) The new charges shall take effect beginning on
12577	12577	22 the first billing day of the following January billing
12578	12578	23 period and remain in effect through the last billing
12579	12579	24 day of the next December billing period regardless of
12580	12580	25 whether the Commission enters upon a hearing under
12581	12581	26 this paragraph (3).
12582	12582
12583	12583
12584	12584
12585	12585
12586	12586
12587	12587	HB3779 - 350 - LRB104 11172 AAS 21254 b
12588	12588
12589	12589
12590	12590	HB3779- 351 -LRB104 11172 AAS 21254 b HB3779 - 351 - LRB104 11172 AAS 21254 b
12591	12591	HB3779 - 351 - LRB104 11172 AAS 21254 b
12592	12592	1 (C) The filing shall include relevant and
12593	12593	2 necessary data and documentation for the applicable
12594	12594	3 rate year. Normalization adjustments shall not be
12595	12595	4 required.
12596	12596	5 Within 45 days after the utility files its annual
12597	12597	6 update of cost inputs to the energy efficiency formula
12598	12598	7 rate, the Commission shall with reasonable notice,
12599	12599	8 initiate a proceeding concerning whether the projected
12600	12600	9 costs to be incurred by the utility and recovered during
12601	12601	10 the applicable rate year, and that are reflected in the
12602	12602	11 inputs to the energy efficiency formula rate, are
12603	12603	12 consistent with the utility's approved multi-year plan
12604	12604	13 under subsections (f) and (g) of this Section and whether
12605	12605	14 the costs incurred by the utility during the prior rate
12606	12606	15 year were prudent and reasonable. The Commission shall
12607	12607	16 also have the authority to investigate the information and
12608	12608	17 data described in paragraph (9) of subsection (g) of this
12609	12609	18 Section, including the proposed adjustment to the
12610	12610	19 utility's return on equity component of its weighted
12611	12611	20 average cost of capital. During the course of the
12612	12612	21 proceeding, each objection shall be stated with
12613	12613	22 particularity and evidence provided in support thereof,
12614	12614	23 after which the utility shall have the opportunity to
12615	12615	24 rebut the evidence. Discovery shall be allowed consistent
12616	12616	25 with the Commission's Rules of Practice, which Rules of
12617	12617	26 Practice shall be enforced by the Commission or the
12618	12618
12619	12619
12620	12620
12621	12621
12622	12622
12623	12623	HB3779 - 351 - LRB104 11172 AAS 21254 b
12624	12624
12625	12625
12626	12626	HB3779- 352 -LRB104 11172 AAS 21254 b HB3779 - 352 - LRB104 11172 AAS 21254 b
12627	12627	HB3779 - 352 - LRB104 11172 AAS 21254 b
12628	12628	1 assigned administrative law judge. The Commission shall
12629	12629	2 apply the same evidentiary standards, including, but not
12630	12630	3 limited to, those concerning the prudence and
12631	12631	4 reasonableness of the costs incurred by the utility,
12632	12632	5 during the proceeding as it would apply in a proceeding to
12633	12633	6 review a filing for a general increase in rates under
12634	12634	7 Article IX of this Act. The Commission shall not, however,
12635	12635	8 have the authority in a proceeding under this paragraph
12636	12636	9 (3) to consider or order any changes to the structure or
12637	12637	10 protocols of the energy efficiency formula rate approved
12638	12638	11 under paragraph (2) of this subsection (d). In a
12639	12639	12 proceeding under this paragraph (3), the Commission shall
12640	12640	13 enter its order no later than the earlier of 195 days after
12641	12641	14 the utility's filing of its annual update of cost inputs
12642	12642	15 to the energy efficiency formula rate or December 15. The
12643	12643	16 utility's proposed return on equity calculation, as
12644	12644	17 described in paragraphs (7) through (9) of subsection (g)
12645	12645	18 of this Section, shall be deemed the final, approved
12646	12646	19 calculation on December 15 of the year in which it is filed
12647	12647	20 unless the Commission enters an order on or before
12648	12648	21 December 15, after notice and hearing, that modifies such
12649	12649	22 calculation consistent with this Section. The Commission's
12650	12650	23 determinations of the prudence and reasonableness of the
12651	12651	24 costs incurred, and determination of such return on equity
12652	12652	25 calculation, for the applicable calendar year shall be
12653	12653	26 final upon entry of the Commission's order and shall not
12654	12654
12655	12655
12656	12656
12657	12657
12658	12658
12659	12659	HB3779 - 352 - LRB104 11172 AAS 21254 b
12660	12660
12661	12661
12662	12662	HB3779- 353 -LRB104 11172 AAS 21254 b HB3779 - 353 - LRB104 11172 AAS 21254 b
12663	12663	HB3779 - 353 - LRB104 11172 AAS 21254 b
12664	12664	1 be subject to reopening, reexamination, or collateral
12665	12665	2 attack in any other Commission proceeding, case, docket,
12666	12666	3 order, rule, or regulation; however, nothing in this
12667	12667	4 paragraph (3) shall prohibit a party from petitioning the
12668	12668	5 Commission to rehear or appeal to the courts the order
12669	12669	6 under the provisions of this Act.
12670	12670	7 (e) Beginning on June 1, 2017 (the effective date of
12671	12671	8 Public Act 99-906), a utility subject to the requirements of
12672	12672	9 this Section may elect to defer, as a regulatory asset, up to
12673	12673	10 the full amount of its expenditures incurred under this
12674	12674	11 Section for each annual period, including, but not limited to,
12675	12675	12 any expenditures incurred above the funding level set by
12676	12676	13 subsection (f) of this Section for a given year. The total
12677	12677	14 expenditures deferred as a regulatory asset in a given year
12678	12678	15 shall be amortized and recovered over a period that is equal to
12679	12679	16 the weighted average of the energy efficiency measure lives
12680	12680	17 implemented for that year that are reflected in the regulatory
12681	12681	18 asset. The unamortized balance shall be recognized as of
12682	12682	19 December 31 for a given year. The utility shall also earn a
12683	12683	20 return on the total of the unamortized balances of all of the
12684	12684	21 energy efficiency regulatory assets, less any deferred taxes
12685	12685	22 related to those unamortized balances, at an annual rate equal
12686	12686	23 to the utility's weighted average cost of capital that
12687	12687	24 includes, based on a year-end capital structure, the utility's
12688	12688	25 actual cost of debt for the applicable calendar year and a cost
12689	12689	26 of equity, which shall be calculated through calendar year
12690	12690
12691	12691
12692	12692
12693	12693
12694	12694
12695	12695	HB3779 - 353 - LRB104 11172 AAS 21254 b
12696	12696
12697	12697
12698	12698	HB3779- 354 -LRB104 11172 AAS 21254 b HB3779 - 354 - LRB104 11172 AAS 21254 b
12699	12699	HB3779 - 354 - LRB104 11172 AAS 21254 b
12700	12700	1 2025 as the sum of the (i) the average for the applicable
12701	12701	2 calendar year of the monthly average yields of 30-year U.S.
12702	12702	3 Treasury bonds published by the Board of Governors of the
12703	12703	4 Federal Reserve System in its weekly H.15 Statistical Release
12704	12704	5 or successor publication; and (ii) 580 basis points, including
12705	12705	6 a revenue conversion factor calculated to recover or refund
12706	12706	7 all additional income taxes that may be payable or receivable
12707	12707	8 as a result of that return; for 2026 and subsequent years the
12708	12708	9 utility's cost of equity shall be the value most recently
12709	12709	10 approved by the Commission for the utility's capital
12710	12710	11 investments in its distribution system. Capital investment
12711	12711	12 costs shall be depreciated and recovered over their useful
12712	12712	13 lives consistent with generally accepted accounting
12713	12713	14 principles. The weighted average cost of capital shall be
12714	12714	15 applied to the capital investment cost balance, less any
12715	12715	16 accumulated depreciation and accumulated deferred income
12716	12716	17 taxes, as of December 31 for a given year.
12717	12717	18 When an electric utility creates a regulatory asset under
12718	12718	19 the provisions of this Section, the costs are recovered over a
12719	12719	20 period during which customers also receive a benefit which is
12720	12720	21 in the public interest. Accordingly, it is the intent of the
12721	12721	22 General Assembly that an electric utility that elects to
12722	12722	23 create a regulatory asset under the provisions of this Section
12723	12723	24 shall recover all of the associated costs as set forth in this
12724	12724	25 Section. After the Commission has approved the prudence and
12725	12725	26 reasonableness of the costs that comprise the regulatory
12726	12726
12727	12727
12728	12728
12729	12729
12730	12730
12731	12731	HB3779 - 354 - LRB104 11172 AAS 21254 b
12732	12732
12733	12733
12734	12734	HB3779- 355 -LRB104 11172 AAS 21254 b HB3779 - 355 - LRB104 11172 AAS 21254 b
12735	12735	HB3779 - 355 - LRB104 11172 AAS 21254 b
12736	12736	1 asset, the electric utility shall be permitted to recover all
12737	12737	2 such costs, and the value and recoverability through rates of
12738	12738	3 the associated regulatory asset shall not be limited, altered,
12739	12739	4 impaired, or reduced.
12740	12740	5 (f) Beginning in 2017, each electric utility shall file an
12741	12741	6 energy efficiency plan with the Commission to meet the energy
12742	12742	7 efficiency standards for the next applicable multi-year period
12743	12743	8 beginning January 1 of the year following the filing,
12744	12744	9 according to the schedule set forth in paragraphs (1) through
12745	12745	10 (3) of this subsection (f). If a utility does not file such a
12746	12746	11 plan on or before the applicable filing deadline for the plan,
12747	12747	12 it shall face a penalty of $100,000 per day until the plan is
12748	12748	13 filed.
12749	12749	14 (1) No later than 30 days after June 1, 2017 (the
12750	12750	15 effective date of Public Act 99-906), each electric
12751	12751	16 utility shall file a 4-year energy efficiency plan
12752	12752	17 commencing on January 1, 2018 that is designed to achieve
12753	12753	18 the cumulative persisting annual savings goals specified
12754	12754	19 in paragraphs (1) through (4) of subsection (b-5) of this
12755	12755	20 Section or in paragraphs (1) through (4) of subsection
12756	12756	21 (b-15) of this Section, as applicable, through
12757	12757	22 implementation of energy efficiency measures; however, the
12758	12758	23 goals may be reduced if the utility's expenditures are
12759	12759	24 limited pursuant to subsection (m) of this Section or, for
12760	12760	25 a utility that serves less than 3,000,000 retail
12761	12761	26 customers, if each of the following conditions are met:
12762	12762
12763	12763
12764	12764
12765	12765
12766	12766
12767	12767	HB3779 - 355 - LRB104 11172 AAS 21254 b
12768	12768
12769	12769
12770	12770	HB3779- 356 -LRB104 11172 AAS 21254 b HB3779 - 356 - LRB104 11172 AAS 21254 b
12771	12771	HB3779 - 356 - LRB104 11172 AAS 21254 b
12772	12772	1 (A) the plan's analysis and forecasts of the utility's
12773	12773	2 ability to acquire energy savings demonstrate that
12774	12774	3 achievement of such goals is not cost effective; and (B)
12775	12775	4 the amount of energy savings achieved by the utility as
12776	12776	5 determined by the independent evaluator for the most
12777	12777	6 recent year for which savings have been evaluated
12778	12778	7 preceding the plan filing was less than the average annual
12779	12779	8 amount of savings required to achieve the goals for the
12780	12780	9 applicable 4-year plan period. Except as provided in
12781	12781	10 subsection (m) of this Section, annual increases in
12782	12782	11 cumulative persisting annual savings goals during the
12783	12783	12 applicable 4-year plan period shall not be reduced to
12784	12784	13 amounts that are less than the maximum amount of
12785	12785	14 cumulative persisting annual savings that is forecast to
12786	12786	15 be cost-effectively achievable during the 4-year plan
12787	12787	16 period. The Commission shall review any proposed goal
12788	12788	17 reduction as part of its review and approval of the
12789	12789	18 utility's proposed plan.
12790	12790	19 (2) No later than March 1, 2021, each electric utility
12791	12791	20 shall file a 4-year energy efficiency plan commencing on
12792	12792	21 January 1, 2022 that is designed to achieve the cumulative
12793	12793	22 persisting annual savings goals specified in paragraphs
12794	12794	23 (5) through (8) of subsection (b-5) of this Section or in
12795	12795	24 paragraphs (5) through (8) of subsection (b-15) of this
12796	12796	25 Section, as applicable, through implementation of energy
12797	12797	26 efficiency measures; however, the goals may be reduced if
12798	12798
12799	12799
12800	12800
12801	12801
12802	12802
12803	12803	HB3779 - 356 - LRB104 11172 AAS 21254 b
12804	12804
12805	12805
12806	12806	HB3779- 357 -LRB104 11172 AAS 21254 b HB3779 - 357 - LRB104 11172 AAS 21254 b
12807	12807	HB3779 - 357 - LRB104 11172 AAS 21254 b
12808	12808	1 either (1) clear and convincing evidence demonstrates,
12809	12809	2 through independent analysis, that the expenditure limits
12810	12810	3 in subsection (m) of this Section preclude full
12811	12811	4 achievement of the goals or (2) each of the following
12812	12812	5 conditions are met: (A) the plan's analysis and forecasts
12813	12813	6 of the utility's ability to acquire energy savings
12814	12814	7 demonstrate by clear and convincing evidence and through
12815	12815	8 independent analysis that achievement of such goals is not
12816	12816	9 cost effective; and (B) the amount of energy savings
12817	12817	10 achieved by the utility as determined by the independent
12818	12818	11 evaluator for the most recent year for which savings have
12819	12819	12 been evaluated preceding the plan filing was less than the
12820	12820	13 average annual amount of savings required to achieve the
12821	12821	14 goals for the applicable 4-year plan period. If there is
12822	12822	15 not clear and convincing evidence that achieving the
12823	12823	16 savings goals specified in paragraph (b-5) or (b-15) of
12824	12824	17 this Section is possible both cost-effectively and within
12825	12825	18 the expenditure limits in subsection (m), such savings
12826	12826	19 goals shall not be reduced. Except as provided in
12827	12827	20 subsection (m) of this Section, annual increases in
12828	12828	21 cumulative persisting annual savings goals during the
12829	12829	22 applicable 4-year plan period shall not be reduced to
12830	12830	23 amounts that are less than the maximum amount of
12831	12831	24 cumulative persisting annual savings that is forecast to
12832	12832	25 be cost-effectively achievable during the 4-year plan
12833	12833	26 period. The Commission shall review any proposed goal
12834	12834
12835	12835
12836	12836
12837	12837
12838	12838
12839	12839	HB3779 - 357 - LRB104 11172 AAS 21254 b
12840	12840
12841	12841
12842	12842	HB3779- 358 -LRB104 11172 AAS 21254 b HB3779 - 358 - LRB104 11172 AAS 21254 b
12843	12843	HB3779 - 358 - LRB104 11172 AAS 21254 b
12844	12844	1 reduction as part of its review and approval of the
12845	12845	2 utility's proposed plan.
12846	12846	3 (2.5) The energy efficiency plans of electric
12847	12847	4 utilities that were approved by the Commission for
12848	12848	5 calendar years 2022 through 2025, including any stipulated
12849	12849	6 agreements between the utility and other parties that were
12850	12850	7 approved by the Commission, shall continue to be in force
12851	12851	8 through calendar year 2026. The utilities' savings goals
12852	12852	9 for 2026 shall be the applicable incremental annual
12853	12853	10 savings goals implicit in the growth in cumulative
12854	12854	11 persisting annual savings set forth in paragraphs (b-5)
12855	12855	12 and (b-15) of this Section.
12856	12856	13 (3) No later than March 1, 2026 2025, each electric
12857	12857	14 utility shall file a 3-year 4-year energy efficiency plan
12858	12858	15 commencing on January 1, 2027 2026 that is designed to
12859	12859	16 achieve lifetime savings equal to the product of the
12860	12860	17 incremental annual savings goal and the minimum average
12861	12861	18 savings life defined by subsection (b-16) the cumulative
12862	12862	19 persisting annual savings goals specified in paragraphs
12863	12863	20 (9) through (12) of subsection (b-5) of this Section or in
12864	12864	21 paragraphs (9) through (12) of subsection (b-15) of this
12865	12865	22 Section, as applicable, through implementation of energy
12866	12866	23 efficiency measures; however, the goals may be reduced if
12867	12867	24 either (1) clear and convincing evidence demonstrates,
12868	12868	25 through independent analysis, that the expenditure limits
12869	12869	26 in subsection (m) of this Section preclude full
12870	12870
12871	12871
12872	12872
12873	12873
12874	12874
12875	12875	HB3779 - 358 - LRB104 11172 AAS 21254 b
12876	12876
12877	12877
12878	12878	HB3779- 359 -LRB104 11172 AAS 21254 b HB3779 - 359 - LRB104 11172 AAS 21254 b
12879	12879	HB3779 - 359 - LRB104 11172 AAS 21254 b
12880	12880	1 achievement of the goals or (2) each of the following
12881	12881	2 conditions are met: (A) the plan's analysis and forecasts
12882	12882	3 of the utility's ability to acquire energy savings
12883	12883	4 demonstrate by clear and convincing evidence and through
12884	12884	5 independent analysis that achievement of such goals is not
12885	12885	6 cost effective; and (B) the amount of energy savings
12886	12886	7 achieved by the utility as determined by the independent
12887	12887	8 evaluator for the most recent year for which savings have
12888	12888	9 been evaluated preceding the plan filing was less than the
12889	12889	10 average annual amount of savings required to achieve the
12890	12890	11 goals for the applicable 4-year plan period. If there is
12891	12891	12 not clear and convincing evidence that achieving the
12892	12892	13 savings goals specified in paragraphs (b-5) or (b-15) of
12893	12893	14 this Section is possible both cost-effectively and within
12894	12894	15 the expenditure limits in subsection (m), such savings
12895	12895	16 goals shall not be reduced. Except as provided in
12896	12896	17 subsection (m) of this Section, annual increases in
12897	12897	18 cumulative persisting annual savings goals during the
12898	12898	19 applicable 4-year plan period shall not be reduced to
12899	12899	20 amounts that are less than the maximum amount of
12900	12900	21 cumulative persisting annual savings that is forecast to
12901	12901	22 be cost-effectively achievable during the 4-year plan
12902	12902	23 period. The Commission shall review any proposed goal
12903	12903	24 reduction as part of its review and approval of the
12904	12904	25 utility's proposed plan.
12905	12905	26 (4) No later than March 1, 2029, and every 4 years
12906	12906
12907	12907
12908	12908
12909	12909
12910	12910
12911	12911	HB3779 - 359 - LRB104 11172 AAS 21254 b
12912	12912
12913	12913
12914	12914	HB3779- 360 -LRB104 11172 AAS 21254 b HB3779 - 360 - LRB104 11172 AAS 21254 b
12915	12915	HB3779 - 360 - LRB104 11172 AAS 21254 b
12916	12916	1 thereafter, each electric utility shall file a 4-year
12917	12917	2 energy efficiency plan commencing on January 1, 2030, and
12918	12918	3 every 4 years thereafter, respectively, that is designed
12919	12919	4 to achieve lifetime savings equal to the product of the
12920	12920	5 incremental annual savings goal and the minimum average
12921	12921	6 savings life described in subsection (b-16) the cumulative
12922	12922	7 persisting annual savings goals established by the
12923	12923	8 Illinois Commerce Commission pursuant to direction of
12924	12924	9 subsections (b-5) and (b-15) of this Section, as
12925	12925	10 applicable, through implementation of energy efficiency
12926	12926	11 measures; however, the goals may be reduced if either (1)
12927	12927	12 clear and convincing evidence and independent analysis
12928	12928	13 demonstrates that the expenditure limits in subsection (m)
12929	12929	14 of this Section preclude full achievement of the goals or
12930	12930	15 (2) each of the following conditions are met: (A) the
12931	12931	16 plan's analysis and forecasts of the utility's ability to
12932	12932	17 acquire energy savings demonstrate by clear and convincing
12933	12933	18 evidence and through independent analysis that achievement
12934	12934	19 of such goals is not cost-effective; and (B) the amount of
12935	12935	20 energy savings achieved by the utility as determined by
12936	12936	21 the independent evaluator for the most recent year for
12937	12937	22 which savings have been evaluated preceding the plan
12938	12938	23 filing was less than the average annual amount of savings
12939	12939	24 required to achieve the goals for the applicable multiyear
12940	12940	25 4-year plan period. If there is not clear and convincing
12941	12941	26 evidence that achieving the savings goals specified in
12942	12942
12943	12943
12944	12944
12945	12945
12946	12946
12947	12947	HB3779 - 360 - LRB104 11172 AAS 21254 b
12948	12948
12949	12949
12950	12950	HB3779- 361 -LRB104 11172 AAS 21254 b HB3779 - 361 - LRB104 11172 AAS 21254 b
12951	12951	HB3779 - 361 - LRB104 11172 AAS 21254 b
12952	12952	1 paragraph (b-16) paragraphs (b-5) or (b-15) of this
12953	12953	2 Section is possible both cost-effectively and within the
12954	12954	3 expenditure limits in subsection (m), such savings goals
12955	12955	4 shall not be reduced. Except as provided in subsection (m)
12956	12956	5 of this Section, annual increases in cumulative persisting
12957	12957	6 annual savings goals during the applicable 4-year plan
12958	12958	7 period shall not be reduced to amounts that are less than
12959	12959	8 the maximum amount of cumulative persisting annual savings
12960	12960	9 that is forecast to be cost-effectively achievable during
12961	12961	10 the 4-year plan period. The Commission shall review any
12962	12962	11 proposed goal reduction as part of its review and approval
12963	12963	12 of the utility's proposed plan.
12964	12964	13 Each utility's plan shall set forth the utility's
12965	12965	14 proposals to meet the energy efficiency standards identified
12966	12966	15 in subsection (b-5), or (b-15), or (b-16), as applicable and
12967	12967	16 as such standards may have been modified under this subsection
12968	12968	17 (f), taking into account the unique circumstances of the
12969	12969	18 utility's service territory. For those plans commencing on
12970	12970	19 January 1, 2018, the Commission shall seek public comment on
12971	12971	20 the utility's plan and shall issue an order approving or
12972	12972	21 disapproving each plan no later than 105 days after June 1,
12973	12973	22 2017 (the effective date of Public Act 99-906). For those
12974	12974	23 plans commencing after December 31, 2021, the Commission shall
12975	12975	24 seek public comment on the utility's plan and shall issue an
12976	12976	25 order approving or disapproving each plan within 6 months
12977	12977	26 after its submission. If the Commission disapproves a plan,
12978	12978
12979	12979
12980	12980
12981	12981
12982	12982
12983	12983	HB3779 - 361 - LRB104 11172 AAS 21254 b
12984	12984
12985	12985
12986	12986	HB3779- 362 -LRB104 11172 AAS 21254 b HB3779 - 362 - LRB104 11172 AAS 21254 b
12987	12987	HB3779 - 362 - LRB104 11172 AAS 21254 b
12988	12988	1 the Commission shall, within 30 days, describe in detail the
12989	12989	2 reasons for the disapproval and describe a path by which the
12990	12990	3 utility may file a revised draft of the plan to address the
12991	12991	4 Commission's concerns satisfactorily. If the utility does not
12992	12992	5 refile with the Commission within 60 days, the utility shall
12993	12993	6 be subject to penalties at a rate of $100,000 per day until the
12994	12994	7 plan is filed. This process shall continue, and penalties
12995	12995	8 shall accrue, until the utility has successfully filed a
12996	12996	9 portfolio of energy efficiency and demand-response measures.
12997	12997	10 Penalties shall be deposited into the Energy Efficiency Trust
12998	12998	11 Fund.
12999	12999	12 (g) In submitting proposed plans and funding levels under
13000	13000	13 subsection (f) of this Section to meet the savings goals
13001	13001	14 identified in subsection (b-5), or (b-15), or (b-16) of this
13002	13002	15 Section, as applicable, the utility shall:
13003	13003	16 (1) Demonstrate that its proposed energy efficiency
13004	13004	17 measures will achieve the applicable requirements that are
13005	13005	18 identified in subsection (b-5), or (b-15), or (b-16) of
13006	13006	19 this Section, as modified by subsection (f) of this
13007	13007	20 Section.
13008	13008	21 (2) (Blank).
13009	13009	22 (2.5) Demonstrate consideration of program options for
13010	13010	23 (A) advancing new building codes, appliance standards, and
13011	13011	24 municipal regulations governing existing and new building
13012	13012	25 efficiency improvements and (B) supporting efforts to
13013	13013	26 improve compliance with new building codes, appliance
13014	13014
13015	13015
13016	13016
13017	13017
13018	13018
13019	13019	HB3779 - 362 - LRB104 11172 AAS 21254 b
13020	13020
13021	13021
13022	13022	HB3779- 363 -LRB104 11172 AAS 21254 b HB3779 - 363 - LRB104 11172 AAS 21254 b
13023	13023	HB3779 - 363 - LRB104 11172 AAS 21254 b
13024	13024	1 standards and municipal regulations, as potentially
13025	13025	2 cost-effective means of acquiring energy savings to count
13026	13026	3 toward savings goals.
13027	13027	4 (3) Demonstrate that its overall portfolio of
13028	13028	5 measures, not including low-income programs described in
13029	13029	6 subsection (c) of this Section, is cost-effective using
13030	13030	7 the total resource cost test or complies with paragraphs
13031	13031	8 (1) through (3) of subsection (f) of this Section and
13032	13032	9 represents a diverse cross-section of opportunities for
13033	13033	10 customers of all rate classes, other than those customers
13034	13034	11 described in subsection (l) of this Section, to
13035	13035	12 participate in the programs. Individual measures need not
13036	13036	13 be cost effective.
13037	13037	14 (3.5) Demonstrate that the utility's plan integrates
13038	13038	15 the delivery of energy efficiency programs with natural
13039	13039	16 gas efficiency programs, programs promoting distributed
13040	13040	17 solar, programs promoting demand response and other
13041	13041	18 efforts to address bill payment issues, including, but not
13042	13042	19 limited to, LIHEAP and the Percentage of Income Payment
13043	13043	20 Plan, to the extent such integration is practical and has
13044	13044	21 the potential to enhance customer engagement, minimize
13045	13045	22 market confusion, or reduce administrative costs.
13046	13046	23 (4) Present a third-party energy efficiency
13047	13047	24 implementation program subject to the following
13048	13048	25 requirements:
13049	13049	26 (A) beginning with the year commencing January 1,
13050	13050
13051	13051
13052	13052
13053	13053
13054	13054
13055	13055	HB3779 - 363 - LRB104 11172 AAS 21254 b
13056	13056
13057	13057
13058	13058	HB3779- 364 -LRB104 11172 AAS 21254 b HB3779 - 364 - LRB104 11172 AAS 21254 b
13059	13059	HB3779 - 364 - LRB104 11172 AAS 21254 b
13060	13060	1 2019, electric utilities that serve more than
13061	13061	2 3,000,000 retail customers in the State shall fund
13062	13062	3 third-party energy efficiency programs in an amount
13063	13063	4 that is no less than $25,000,000 per year, and
13064	13064	5 electric utilities that serve less than 3,000,000
13065	13065	6 retail customers but more than 500,000 retail
13066	13066	7 customers in the State shall fund third-party energy
13067	13067	8 efficiency programs in an amount that is no less than
13068	13068	9 $8,350,000 per year;
13069	13069	10 (B) during 2018, the utility shall conduct a
13070	13070	11 solicitation process for purposes of requesting
13071	13071	12 proposals from third-party vendors for those
13072	13072	13 third-party energy efficiency programs to be offered
13073	13073	14 during one or more of the years commencing January 1,
13074	13074	15 2019, January 1, 2020, and January 1, 2021; for those
13075	13075	16 multi-year plans commencing on January 1, 2022 and
13076	13076	17 January 1, 2026, the utility shall conduct a
13077	13077	18 solicitation process during 2021 and 2025,
13078	13078	19 respectively, for purposes of requesting proposals
13079	13079	20 from third-party vendors for those third-party energy
13080	13080	21 efficiency programs to be offered during one or more
13081	13081	22 years of the respective multi-year plan period; for
13082	13082	23 each solicitation process, the utility shall identify
13083	13083	24 the sector, technology, or geographical area for which
13084	13084	25 it is seeking requests for proposals; the solicitation
13085	13085	26 process must be either for programs that fill gaps in
13086	13086
13087	13087
13088	13088
13089	13089
13090	13090
13091	13091	HB3779 - 364 - LRB104 11172 AAS 21254 b
13092	13092
13093	13093
13094	13094	HB3779- 365 -LRB104 11172 AAS 21254 b HB3779 - 365 - LRB104 11172 AAS 21254 b
13095	13095	HB3779 - 365 - LRB104 11172 AAS 21254 b
13096	13096	1 the utility's program portfolio and for programs that
13097	13097	2 target low-income customers, business sectors,
13098	13098	3 building types, geographies, or other specific parts
13099	13099	4 of its customer base with initiatives that would be
13100	13100	5 more effective at reaching these customer segments
13101	13101	6 than the utilities' programs filed in its energy
13102	13102	7 efficiency plans;
13103	13103	8 (C) the utility shall propose the bidder
13104	13104	9 qualifications, performance measurement process, and
13105	13105	10 contract structure, which must include a performance
13106	13106	11 payment mechanism and general terms and conditions;
13107	13107	12 the proposed qualifications, process, and structure
13108	13108	13 shall be subject to Commission approval; and
13109	13109	14 (D) the utility shall retain an independent third
13110	13110	15 party to score the proposals received through the
13111	13111	16 solicitation process described in this paragraph (4),
13112	13112	17 rank them according to their cost per lifetime
13113	13113	18 kilowatt-hours saved, and assemble the portfolio of
13114	13114	19 third-party programs.
13115	13115	20 The electric utility shall recover all costs
13116	13116	21 associated with Commission-approved, third-party
13117	13117	22 administered programs regardless of the success of those
13118	13118	23 programs.
13119	13119	24 (4.5) Implement cost-effective demand-response
13120	13120	25 measures to reduce peak demand by 0.1% over the prior year
13121	13121	26 for eligible retail customers, as defined in Section
13122	13122
13123	13123
13124	13124
13125	13125
13126	13126
13127	13127	HB3779 - 365 - LRB104 11172 AAS 21254 b
13128	13128
13129	13129
13130	13130	HB3779- 366 -LRB104 11172 AAS 21254 b HB3779 - 366 - LRB104 11172 AAS 21254 b
13131	13131	HB3779 - 366 - LRB104 11172 AAS 21254 b
13132	13132	1 16-111.5 of this Act, and for customers that elect hourly
13133	13133	2 service from the utility pursuant to Section 16-107 of
13134	13134	3 this Act, provided those customers have not been declared
13135	13135	4 competitive. This requirement continues until December 31,
13136	13136	5 2026.
13137	13137	6 (5) Include a proposed or revised cost-recovery tariff
13138	13138	7 mechanism, as provided for under subsection (d) of this
13139	13139	8 Section, to fund the proposed energy efficiency and
13140	13140	9 demand-response measures and to ensure the recovery of the
13141	13141	10 prudently and reasonably incurred costs of
13142	13142	11 Commission-approved programs.
13143	13143	12 (6) Provide for an annual independent evaluation of
13144	13144	13 the performance of the cost-effectiveness of the utility's
13145	13145	14 portfolio of measures, as well as a full review of the
13146	13146	15 multi-year plan results of the broader net program impacts
13147	13147	16 and, to the extent practical, for adjustment of the
13148	13148	17 measures on a going-forward basis as a result of the
13149	13149	18 evaluations. The resources dedicated to evaluation shall
13150	13150	19 not exceed 3% of portfolio resources in any given year.
13151	13151	20 (7) For electric utilities that serve more than
13152	13152	21 500,000 3,000,000 retail customers in the State:
13153	13153	22 (A) Through December 31, 2025, provide for an
13154	13154	23 adjustment to the return on equity component of the
13155	13155	24 utility's weighted average cost of capital calculated
13156	13156	25 under subsection (d) of this Section:
13157	13157	26 (i) If the independent evaluator determines
13158	13158
13159	13159
13160	13160
13161	13161
13162	13162
13163	13163	HB3779 - 366 - LRB104 11172 AAS 21254 b
13164	13164
13165	13165
13166	13166	HB3779- 367 -LRB104 11172 AAS 21254 b HB3779 - 367 - LRB104 11172 AAS 21254 b
13167	13167	HB3779 - 367 - LRB104 11172 AAS 21254 b
13168	13168	1 that the utility achieved a cumulative persisting
13169	13169	2 annual savings that is less than the applicable
13170	13170	3 annual incremental goal, then the return on equity
13171	13171	4 component shall be reduced by a maximum of 200
13172	13172	5 basis points in the event that the utility
13173	13173	6 achieved no more than 75% of such goal. If the
13174	13174	7 utility achieved more than 75% of the applicable
13175	13175	8 annual incremental goal but less than 100% of such
13176	13176	9 goal, then the return on equity component shall be
13177	13177	10 reduced by 8 basis points for each percent by
13178	13178	11 which the utility failed to achieve the goal.
13179	13179	12 (ii) If the independent evaluator determines
13180	13180	13 that the utility achieved a cumulative persisting
13181	13181	14 annual savings that is more than the applicable
13182	13182	15 annual incremental goal, then the return on equity
13183	13183	16 component shall be increased by a maximum of 200
13184	13184	17 basis points in the event that the utility
13185	13185	18 achieved at least 125% of such goal. If the
13186	13186	19 utility achieved more than 100% of the applicable
13187	13187	20 annual incremental goal but less than 125% of such
13188	13188	21 goal, then the return on equity component shall be
13189	13189	22 increased by 8 basis points for each percent by
13190	13190	23 which the utility achieved above the goal. If the
13191	13191	24 applicable annual incremental goal was reduced
13192	13192	25 under paragraph (1) or (2) of subsection (f) of
13193	13193	26 this Section, then the following adjustments shall
13194	13194
13195	13195
13196	13196
13197	13197
13198	13198
13199	13199	HB3779 - 367 - LRB104 11172 AAS 21254 b
13200	13200
13201	13201
13202	13202	HB3779- 368 -LRB104 11172 AAS 21254 b HB3779 - 368 - LRB104 11172 AAS 21254 b
13203	13203	HB3779 - 368 - LRB104 11172 AAS 21254 b
13204	13204	1 be made to the calculations described in this item
13205	13205	2 (ii):
13206	13206	3 (aa) the calculation for determining
13207	13207	4 achievement that is at least 125% of the
13208	13208	5 applicable annual incremental goal shall use
13209	13209	6 the unreduced applicable annual incremental
13210	13210	7 goal to set the value; and
13211	13211	8 (bb) the calculation for determining
13212	13212	9 achievement that is less than 125% but more
13213	13213	10 than 100% of the applicable annual incremental
13214	13214	11 goal shall use the reduced applicable annual
13215	13215	12 incremental goal to set the value for 100%
13216	13216	13 achievement of the goal and shall use the
13217	13217	14 unreduced goal to set the value for 125%
13218	13218	15 achievement. The 8 basis point value shall
13219	13219	16 also be modified, as necessary, so that the
13220	13220	17 200 basis points are evenly apportioned among
13221	13221	18 each percentage point value between 100% and
13222	13222	19 125% achievement.
13223	13223	20 (B) For the period January 1, 2026 through
13224	13224	21 December 31, 2029 and in all subsequent 4-year
13225	13225	22 periods, provide for an adjustment to the return on
13226	13226	23 equity component of the utility's weighted average
13227	13227	24 cost of capital calculated under subsection (d) of
13228	13228	25 this Section:
13229	13229	26 (i) If the product of the incremental annual
13230	13230
13231	13231
13232	13232
13233	13233
13234	13234
13235	13235	HB3779 - 368 - LRB104 11172 AAS 21254 b
13236	13236
13237	13237
13238	13238	HB3779- 369 -LRB104 11172 AAS 21254 b HB3779 - 369 - LRB104 11172 AAS 21254 b
13239	13239	HB3779 - 369 - LRB104 11172 AAS 21254 b
13240	13240	1 savings goal and minimum average savings life
13241	13241	2 specified in subsection (b-16) of this Section is
13242	13242	3 unmodified, and if the independent evaluator
13243	13243	4 determines that the utility achieved lifetime
13244	13244	5 energy savings that are less than the product of
13245	13245	6 the incremental annual savings goal and minimum
13246	13246	7 average savings life specified in subsection
13247	13247	8 (b-16) of this Section, then the return on equity
13248	13248	9 component shall be reduced by a maximum of 200
13249	13249	10 basis points if the utility achieved no more than
13250	13250	11 66.67% of the lifetime savings goal. If the
13251	13251	12 utility achieved more than 66.67% but less than
13252	13252	13 100% of the goal, then the return on equity
13253	13253	14 component shall be reduced by 6 basis points for
13254	13254	15 each percent by which the utility failed to
13255	13255	16 achieve the goal. If the independent evaluator
13256	13256	17 determines that the utility achieved a cumulative
13257	13257	18 persisting annual savings that is less than the
13258	13258	19 applicable annual incremental goal, then the
13259	13259	20 return on equity component shall be reduced by a
13260	13260	21 maximum of 200 basis points in the event that the
13261	13261	22 utility achieved no more than 66% of such goal. If
13262	13262	23 the utility achieved more than 66% of the
13263	13263	24 applicable annual incremental goal but less than
13264	13264	25 100% of such goal, then the return on equity
13265	13265	26 component shall be reduced by 6 basis points for
13266	13266
13267	13267
13268	13268
13269	13269
13270	13270
13271	13271	HB3779 - 369 - LRB104 11172 AAS 21254 b
13272	13272
13273	13273
13274	13274	HB3779- 370 -LRB104 11172 AAS 21254 b HB3779 - 370 - LRB104 11172 AAS 21254 b
13275	13275	HB3779 - 370 - LRB104 11172 AAS 21254 b
13276	13276	1 each percent by which the utility failed to
13277	13277	2 achieve the goal.
13278	13278	3 (ii) If the product of the incremental annual
13279	13279	4 savings goal and the minimum average savings life
13280	13280	5 specified in subsection (b-16) of this Section is
13281	13281	6 unmodified, and if the independent evaluator
13282	13282	7 determines that the utility achieved lifetime
13283	13283	8 energy savings that are more than the product of
13284	13284	9 the incremental annual savings goal and minimum
13285	13285	10 average savings life specified in subsection
13286	13286	11 (b-16) of this Section, then the return on equity
13287	13287	12 component shall be increased by a maximum of 200
13288	13288	13 basis points if the utility achieved at least
13289	13289	14 133.33% of such lifetime savings goal. If the
13290	13290	15 utility achieved more than 100% but less than
13291	13291	16 133.33% of the goal, then the return on equity
13292	13292	17 component shall be increased by 6 basis points for
13293	13293	18 each percent by which the utility exceeded the
13294	13294	19 goal. If the independent evaluator determines that
13295	13295	20 the utility achieved a cumulative persisting
13296	13296	21 annual savings that is more than the applicable
13297	13297	22 annual incremental goal, then the return on equity
13298	13298	23 component shall be increased by a maximum of 200
13299	13299	24 basis points in the event that the utility
13300	13300	25 achieved at least 134% of such goal. If the
13301	13301	26 utility achieved more than 100% of the applicable
13302	13302
13303	13303
13304	13304
13305	13305
13306	13306
13307	13307	HB3779 - 370 - LRB104 11172 AAS 21254 b
13308	13308
13309	13309
13310	13310	HB3779- 371 -LRB104 11172 AAS 21254 b HB3779 - 371 - LRB104 11172 AAS 21254 b
13311	13311	HB3779 - 371 - LRB104 11172 AAS 21254 b
13312	13312	1 annual incremental goal but less than 134% of such
13313	13313	2 goal, then the return on equity component shall be
13314	13314	3 increased by 6 basis points for each percent by
13315	13315	4 which the utility achieved above the goal. If the
13316	13316	5 applicable annual incremental goal was reduced
13317	13317	6 under paragraph (3) of subsection (f) of this
13318	13318	7 Section, then the following adjustments shall be
13319	13319	8 made to the calculations described in this item
13320	13320	9 (ii):
13321	13321	10 (iii) If the product of the incremental annual
13322	13322	11 savings goal and minimum average savings life
13323	13323	12 specified in subsection (b-16) of this Section is
13324	13324	13 reduced under paragraph (4) of subsection (f),
13325	13325	14 then the return on equity shall be reduced by 10
13326	13326	15 basis points for every percent by which the
13327	13327	16 utility fails to achieve the modified goal, up to
13328	13328	17 a maximum of a 200 basis point reduction for
13329	13329	18 achieving 80% or less of the modified lifetime
13330	13330	19 savings goal. (aa) the calculation for determining
13331	13331	20 achievement that is at least 134% of the
13332	13332	21 applicable annual incremental goal shall use the
13333	13333	22 unreduced applicable annual incremental goal to
13334	13334	23 set the value; and
13335	13335	24 (iv) If the product of the incremental annual
13336	13336	25 savings goal and minimum average savings life
13337	13337	26 specified in subsection (b-16) of this Section is
13338	13338
13339	13339
13340	13340
13341	13341
13342	13342
13343	13343	HB3779 - 371 - LRB104 11172 AAS 21254 b
13344	13344
13345	13345
13346	13346	HB3779- 372 -LRB104 11172 AAS 21254 b HB3779 - 372 - LRB104 11172 AAS 21254 b
13347	13347	HB3779 - 372 - LRB104 11172 AAS 21254 b
13348	13348	1 reduced under paragraph (4) of subsection (f), the
13349	13349	2 return on equity component shall be increased by a
13350	13350	3 maximum of 200 basis points if the utility
13351	13351	4 achieved at least 133.33% of the unmodified
13352	13352	5 lifetime savings goal. If the utility achieved
13353	13353	6 more than 100% of the modified goal but less than
13354	13354	7 133.33% of the unmodified goal, then the return on
13355	13355	8 equity component shall be linearly interpolated
13356	13356	9 between a 0 basis point increase for meeting 100%
13357	13357	10 of the modified goal and a 200 basis point
13358	13358	11 increase for achieving 133.33% of the unmodified
13359	13359	12 goal. (bb) the calculation for determining
13360	13360	13 achievement that is less than 134% but more than
13361	13361	14 100% of the applicable annual incremental goal
13362	13362	15 shall use the reduced applicable annual
13363	13363	16 incremental goal to set the value for 100%
13364	13364	17 achievement of the goal and shall use the
13365	13365	18 unreduced goal to set the value for 134%
13366	13366	19 achievement. The 6 basis point value shall also be
13367	13367	20 modified, as necessary, so that the 200 basis
13368	13368	21 points are evenly apportioned among each
13369	13369	22 percentage point value between 100% and 134%
13370	13370	23 achievement.
13371	13371	24 (C) Notwithstanding the provisions of
13372	13372	25 subparagraphs (A) and (B) of this paragraph (7), if
13373	13373	26 the applicable annual incremental goal for an electric
13374	13374
13375	13375
13376	13376
13377	13377
13378	13378
13379	13379	HB3779 - 372 - LRB104 11172 AAS 21254 b
13380	13380
13381	13381
13382	13382	HB3779- 373 -LRB104 11172 AAS 21254 b HB3779 - 373 - LRB104 11172 AAS 21254 b
13383	13383	HB3779 - 373 - LRB104 11172 AAS 21254 b
13384	13384	1 utility is ever less than 0.6% of deemed average
13385	13385	2 weather normalized sales of electric power and energy
13386	13386	3 during calendar years 2014, 2015, and 2016, an
13387	13387	4 adjustment to the return on equity component of the
13388	13388	5 utility's weighted average cost of capital calculated
13389	13389	6 under subsection (d) of this Section shall be made as
13390	13390	7 follows:
13391	13391	8 (i) If the independent evaluator determines
13392	13392	9 that the utility achieved a cumulative persisting
13393	13393	10 annual savings that is less than would have been
13394	13394	11 achieved had the applicable annual incremental
13395	13395	12 goal been achieved, then the return on equity
13396	13396	13 component shall be reduced by a maximum of 200
13397	13397	14 basis points if the utility achieved no more than
13398	13398	15 75% of its applicable annual total savings
13399	13399	16 requirement as defined in paragraph (7.5) of this
13400	13400	17 subsection. If the utility achieved more than 75%
13401	13401	18 of the applicable annual total savings requirement
13402	13402	19 but less than 100% of such goal, then the return on
13403	13403	20 equity component shall be reduced by 8 basis
13404	13404	21 points for each percent by which the utility
13405	13405	22 failed to achieve the goal.
13406	13406	23 (ii) If the independent evaluator determines
13407	13407	24 that the utility achieved a cumulative persisting
13408	13408	25 annual savings that is more than would have been
13409	13409	26 achieved had the applicable annual incremental
13410	13410
13411	13411
13412	13412
13413	13413
13414	13414
13415	13415	HB3779 - 373 - LRB104 11172 AAS 21254 b
13416	13416
13417	13417
13418	13418	HB3779- 374 -LRB104 11172 AAS 21254 b HB3779 - 374 - LRB104 11172 AAS 21254 b
13419	13419	HB3779 - 374 - LRB104 11172 AAS 21254 b
13420	13420	1 goal been achieved, then the return on equity
13421	13421	2 component shall be increased by a maximum of 200
13422	13422	3 basis points if the utility achieved at least 125%
13423	13423	4 of its applicable annual total savings
13424	13424	5 requirement. If the utility achieved more than
13425	13425	6 100% of the applicable annual total savings
13426	13426	7 requirement but less than 125% of such goal, then
13427	13427	8 the return on equity component shall be increased
13428	13428	9 by 8 basis points for each percent by which the
13429	13429	10 utility achieved above the applicable annual total
13430	13430	11 savings requirement. If the applicable annual
13431	13431	12 incremental goal was reduced under paragraph (1)
13432	13432	13 or (2) of subsection (f) of this Section, then the
13433	13433	14 following adjustments shall be made to the
13434	13434	15 calculations described in this item (ii):
13435	13435	16 (aa) the calculation for determining
13436	13436	17 achievement that is at least 125% of the
13437	13437	18 applicable annual total savings requirement
13438	13438	19 shall use the unreduced applicable annual
13439	13439	20 incremental goal to set the value; and
13440	13440	21 (bb) the calculation for determining
13441	13441	22 achievement that is less than 125% but more
13442	13442	23 than 100% of the applicable annual total
13443	13443	24 savings requirement shall use the reduced
13444	13444	25 applicable annual incremental goal to set the
13445	13445	26 value for 100% achievement of the goal and
13446	13446
13447	13447
13448	13448
13449	13449
13450	13450
13451	13451	HB3779 - 374 - LRB104 11172 AAS 21254 b
13452	13452
13453	13453
13454	13454	HB3779- 375 -LRB104 11172 AAS 21254 b HB3779 - 375 - LRB104 11172 AAS 21254 b
13455	13455	HB3779 - 375 - LRB104 11172 AAS 21254 b
13456	13456	1 shall use the unreduced goal to set the value
13457	13457	2 for 125% achievement. The 8 basis point value
13458	13458	3 shall also be modified, as necessary, so that
13459	13459	4 the 200 basis points are evenly apportioned
13460	13460	5 among each percentage point value between 100%
13461	13461	6 and 125% achievement.
13462	13462	7 (7.5) For purposes of this Section, the term
13463	13463	8 "applicable annual incremental goal" means the difference
13464	13464	9 between the cumulative persisting annual savings goal for
13465	13465	10 the calendar year that is the subject of the independent
13466	13466	11 evaluator's determination and the cumulative persisting
13467	13467	12 annual savings goal for the immediately preceding calendar
13468	13468	13 year, as such goals are defined in subsections (b-5) and
13469	13469	14 (b-15) of this Section and as these goals may have been
13470	13470	15 modified as provided for under subsection (b-20) and
13471	13471	16 paragraphs (1) and (2) through (3) of subsection (f) of
13472	13472	17 this Section. Under subsections (b), (b-5), (b-10), and
13473	13473	18 (b-15) of this Section, a utility must first replace
13474	13474	19 energy savings from measures that have expired before any
13475	13475	20 progress towards achievement of its applicable annual
13476	13476	21 incremental goal may be counted. Savings may expire
13477	13477	22 because measures installed in previous years have reached
13478	13478	23 the end of their lives, because measures installed in
13479	13479	24 previous years are producing lower savings in the current
13480	13480	25 year than in the previous year, or for other reasons
13481	13481	26 identified by independent evaluators. Notwithstanding
13482	13482
13483	13483
13484	13484
13485	13485
13486	13486
13487	13487	HB3779 - 375 - LRB104 11172 AAS 21254 b
13488	13488
13489	13489
13490	13490	HB3779- 376 -LRB104 11172 AAS 21254 b HB3779 - 376 - LRB104 11172 AAS 21254 b
13491	13491	HB3779 - 376 - LRB104 11172 AAS 21254 b
13492	13492	1 anything else set forth in this Section, the difference
13493	13493	2 between the actual annual incremental savings achieved in
13494	13494	3 any given year, including the replacement of energy
13495	13495	4 savings that have expired, and the applicable annual
13496	13496	5 incremental goal shall not affect adjustments to the
13497	13497	6 return on equity for subsequent calendar years under this
13498	13498	7 subsection (g).
13499	13499	8 In this Section, "applicable annual total savings
13500	13500	9 requirement" means the total amount of new annual savings
13501	13501	10 that the utility must achieve in any given year to achieve
13502	13502	11 the applicable annual incremental goal. This is equal to
13503	13503	12 the applicable annual incremental goal plus the total new
13504	13504	13 annual savings that are required to replace savings that
13505	13505	14 expired in or at the end of the previous year.
13506	13506	15 (8) For electric utilities that serve less than
13507	13507	16 3,000,000 retail customers but more than 500,000 retail
13508	13508	17 customers in the State:
13509	13509	18 (A) Through December 31, 2026 2025, the applicable
13510	13510	19 annual incremental goal shall be compared to the
13511	13511	20 annual incremental savings as determined by the
13512	13512	21 independent evaluator.
13513	13513	22 (i) The return on equity component shall be
13514	13514	23 reduced by 8 basis points for each percent by
13515	13515	24 which the utility did not achieve 84.4% of the
13516	13516	25 applicable annual incremental goal.
13517	13517	26 (ii) The return on equity component shall be
13518	13518
13519	13519
13520	13520
13521	13521
13522	13522
13523	13523	HB3779 - 376 - LRB104 11172 AAS 21254 b
13524	13524
13525	13525
13526	13526	HB3779- 377 -LRB104 11172 AAS 21254 b HB3779 - 377 - LRB104 11172 AAS 21254 b
13527	13527	HB3779 - 377 - LRB104 11172 AAS 21254 b
13528	13528	1 increased by 8 basis points for each percent by
13529	13529	2 which the utility exceeded 100% of the applicable
13530	13530	3 annual incremental goal.
13531	13531	4 (iii) The return on equity component shall not
13532	13532	5 be increased or decreased if the annual
13533	13533	6 incremental savings as determined by the
13534	13534	7 independent evaluator is greater than 84.4% of the
13535	13535	8 applicable annual incremental goal and less than
13536	13536	9 100% of the applicable annual incremental goal.
13537	13537	10 (iv) The return on equity component shall not
13538	13538	11 be increased or decreased by an amount greater
13539	13539	12 than 200 basis points pursuant to this
13540	13540	13 subparagraph (A).
13541	13541	14 (B) For the period of January 1, 2027 2026 through
13542	13542	15 December 31, 2029 , provide for an adjustment to the
13543	13543	16 return on equity component of the utility's weighted
13544	13544	17 average cost of capital calculated under subsection
13545	13545	18 (d) of this Section: and in all subsequent 4-year
13546	13546	19 periods, the applicable annual incremental goal shall
13547	13547	20 be compared to the annual incremental savings as
13548	13548	21 determined by the independent evaluator.
13549	13549	22 (i) The return on equity component shall be
13550	13550	23 reduced by 6 basis points for each percent by
13551	13551	24 which the utility did not achieve 85% 100% of the
13552	13552	25 lifetime savings that is the product of the
13553	13553	26 incremental annual savings goal and the minimum
13554	13554
13555	13555
13556	13556
13557	13557
13558	13558
13559	13559	HB3779 - 377 - LRB104 11172 AAS 21254 b
13560	13560
13561	13561
13562	13562	HB3779- 378 -LRB104 11172 AAS 21254 b HB3779 - 378 - LRB104 11172 AAS 21254 b
13563	13563	HB3779 - 378 - LRB104 11172 AAS 21254 b
13564	13564	1 average savings life specified in subsection
13565	13565	2 (b-16) of this Section, up to a maximum reduction
13566	13566	3 of 200 basis points for achieving 51.67% or less
13567	13567	4 of the lifetime savings goal applicable annual
13568	13568	5 incremental goal.
13569	13569	6 (ii) The return on equity component shall be
13570	13570	7 increased by 6 basis points for each percent by
13571	13571	8 which the utility exceeded 100% of the lifetime
13572	13572	9 savings that is the product of the incremental
13573	13573	10 annual savings goal and the minimum average
13574	13574	11 savings life specified in subsection (b-16) of
13575	13575	12 this Section, up to a maximum increase of 200
13576	13576	13 basis points for achieving 133.33% or more of the
13577	13577	14 lifetime savings goal applicable annual
13578	13578	15 incremental goal.
13579	13579	16 (iii) The return on equity component shall not
13580	13580	17 be increased or decreased by an amount greater
13581	13581	18 than 200 basis points pursuant to this
13582	13582	19 subparagraph (B).
13583	13583	20 (C) For the period of January 1, 2030 through
13584	13584	21 December 31, 2033, provide for an adjustment to the
13585	13585	22 return on equity component of the utility's weighted
13586	13586	23 average cost of capital calculated under subsection
13587	13587	24 (d) of this Section:
13588	13588	25 (i) If the product of the incremental annual
13589	13589	26 savings goal and minimum average savings life
13590	13590
13591	13591
13592	13592
13593	13593
13594	13594
13595	13595	HB3779 - 378 - LRB104 11172 AAS 21254 b
13596	13596
13597	13597
13598	13598	HB3779- 379 -LRB104 11172 AAS 21254 b HB3779 - 379 - LRB104 11172 AAS 21254 b
13599	13599	HB3779 - 379 - LRB104 11172 AAS 21254 b
13600	13600	1 specified in subsection (b-16) of this Section is
13601	13601	2 unmodified, and if the independent evaluator
13602	13602	3 determines that the utility achieved lifetime
13603	13603	4 energy savings that are less than 95% of the
13604	13604	5 product of the incremental annual savings goal and
13605	13605	6 minimum average savings life specified in
13606	13606	7 subsection (b-16) of this Section, the return on
13607	13607	8 equity component shall be reduced by 3 basis
13608	13608	9 points for each percent by which the utility did
13609	13609	10 not achieve 95% of the lifetime savings goal, plus
13610	13610	11 an additional 3 basis point reduction for each
13611	13611	12 percent by which the utility did not achieve 90%
13612	13612	13 of the lifetime savings goal, up to a maximum
13613	13613	14 reduction of 200 basis points for achieving 59.17%
13614	13614	15 or less of the lifetime savings goal.
13615	13615	16 (ii) If the product of the incremental annual
13616	13616	17 savings goal and minimum average savings life
13617	13617	18 specified in subsection (b-16) of this Section is
13618	13618	19 unmodified, and if the independent evaluator
13619	13619	20 determines that the utility achieved lifetime
13620	13620	21 energy savings that are greater than the product
13621	13621	22 of the incremental annual savings goal and minimum
13622	13622	23 average savings life specified in subsection
13623	13623	24 (b-16) of this Section, the return on equity
13624	13624	25 component shall be increased by 6 basis points for
13625	13625	26 each percent by which the utility exceeded 100% of
13626	13626
13627	13627
13628	13628
13629	13629
13630	13630
13631	13631	HB3779 - 379 - LRB104 11172 AAS 21254 b
13632	13632
13633	13633
13634	13634	HB3779- 380 -LRB104 11172 AAS 21254 b HB3779 - 380 - LRB104 11172 AAS 21254 b
13635	13635	HB3779 - 380 - LRB104 11172 AAS 21254 b
13636	13636	1 the lifetime savings goal, up to a maximum
13637	13637	2 increase of 200 basis points for achieving 133.33%
13638	13638	3 or more of the lifetime savings goal.
13639	13639	4 (iii) If the product of the incremental annual
13640	13640	5 savings goal and minimum average savings life
13641	13641	6 specified in subsection (b-16) of this Section is
13642	13642	7 reduced under paragraph (4) of subsection (f), the
13643	13643	8 return on equity component shall be reduced by 10
13644	13644	9 basis points for every percent by which the
13645	13645	10 utility fails to achieve the modified lifetime
13646	13646	11 savings goal, up to a maximum of a 200 basis point
13647	13647	12 reduction for achieving 80% or less of the
13648	13648	13 modified goal.
13649	13649	14 (iv) If the product of the incremental annual
13650	13650	15 savings goal and minimum average savings life
13651	13651	16 specified in subsection (b-16) of this Section is
13652	13652	17 reduced under paragraph (4) of subsection (f), the
13653	13653	18 return on equity component shall be increased by a
13654	13654	19 maximum of 200 basis points if the utility
13655	13655	20 achieved at least 133.33% of the unmodified
13656	13656	21 lifetime savings goal. If the utility achieved
13657	13657	22 more than 100% of the modified goal but less than
13658	13658	23 133.33% of the unmodified goal, then the return on
13659	13659	24 equity component shall be linearly interpolated
13660	13660	25 between a 0 basis point increase for meeting 100%
13661	13661	26 of the modified goal and a 200 basis point
13662	13662
13663	13663
13664	13664
13665	13665
13666	13666
13667	13667	HB3779 - 380 - LRB104 11172 AAS 21254 b
13668	13668
13669	13669
13670	13670	HB3779- 381 -LRB104 11172 AAS 21254 b HB3779 - 381 - LRB104 11172 AAS 21254 b
13671	13671	HB3779 - 381 - LRB104 11172 AAS 21254 b
13672	13672	1 increase for achieving 133.33% of the unmodified
13673	13673	2 goal.
13674	13674	3 (D) For the period of January 1, 2034 through
13675	13675	4 December 31, 2037, as well as for all subsequent
13676	13676	5 four-year plan periods, provide for an adjustment to
13677	13677	6 the return on equity component of the utility's
13678	13678	7 weighted average cost of capital calculated under
13679	13679	8 subsection (d) of this Section:
13680	13680	9 (i) If the product of the incremental annual
13681	13681	10 savings goal and minimum average savings life
13682	13682	11 specified in subsection (b-16) of this Section is
13683	13683	12 unmodified, and if the independent evaluator
13684	13684	13 determines that the utility achieved lifetime
13685	13685	14 energy savings that is less than 100% of the
13686	13686	15 product of the incremental annual savings goal and
13687	13687	16 minimum average savings life specified in
13688	13688	17 subsection (b-16) of this Section, the return on
13689	13689	18 equity component shall be reduced by 6 basis
13690	13690	19 points for each percent by which the utility did
13691	13691	20 not achieve 100% of the lifetime savings goal, up
13692	13692	21 to a maximum reduction of 200 basis points for
13693	13693	22 achieving 66.67% or less of the lifetime savings
13694	13694	23 goal.
13695	13695	24 (ii) If the product of the incremental annual
13696	13696	25 savings goal and minimum average savings life
13697	13697	26 specified in subsection (b-16) of this Section is
13698	13698
13699	13699
13700	13700
13701	13701
13702	13702
13703	13703	HB3779 - 381 - LRB104 11172 AAS 21254 b
13704	13704
13705	13705
13706	13706	HB3779- 382 -LRB104 11172 AAS 21254 b HB3779 - 382 - LRB104 11172 AAS 21254 b
13707	13707	HB3779 - 382 - LRB104 11172 AAS 21254 b
13708	13708	1 unmodified, and if the independent evaluator
13709	13709	2 determines that the utility achieved lifetime
13710	13710	3 energy savings that is greater than the product of
13711	13711	4 the incremental annual savings goal and minimum
13712	13712	5 average savings life specified in subsection
13713	13713	6 (b-16) of this Section, the return on equity
13714	13714	7 component shall be increased by 6 basis points for
13715	13715	8 each percent by which the utility exceeded 100% of
13716	13716	9 the lifetime savings goal, up to a maximum
13717	13717	10 increase of 200 basis points for achieving 133.33%
13718	13718	11 or more of the lifetime savings goal.
13719	13719	12 (iii) If the product of the incremental annual
13720	13720	13 savings goal and minimum average savings life
13721	13721	14 specified in subsection (b-16) of this Section is
13722	13722	15 reduced under paragraph (4) of subsection (f),
13723	13723	16 then the return on equity shall be reduced by 10
13724	13724	17 basis points for every percent by which the
13725	13725	18 utility fails to achieve the modified lifetime
13726	13726	19 savings goal, up to a maximum of a 200 basis point
13727	13727	20 reduction for achieving 80% or less of the
13728	13728	21 modified goal.
13729	13729	22 (iv) If the product of the incremental annual
13730	13730	23 savings goal and minimum average savings life
13731	13731	24 specified in subsection (b-16) of this Section is
13732	13732	25 reduced under paragraph (4) of subsection (f), the
13733	13733	26 return on equity component shall be increased by a
13734	13734
13735	13735
13736	13736
13737	13737
13738	13738
13739	13739	HB3779 - 382 - LRB104 11172 AAS 21254 b
13740	13740
13741	13741
13742	13742	HB3779- 383 -LRB104 11172 AAS 21254 b HB3779 - 383 - LRB104 11172 AAS 21254 b
13743	13743	HB3779 - 383 - LRB104 11172 AAS 21254 b
13744	13744	1 maximum of 200 basis points if the utility
13745	13745	2 achieved at least 133.33% of the unmodified
13746	13746	3 lifetime savings goal. If the utility achieved
13747	13747	4 more than 100% of the modified goal but less than
13748	13748	5 133.33% of the unmodified goal, then the return on
13749	13749	6 equity component shall be linearly interpolated
13750	13750	7 between a 0 basis point increase for meeting 100%
13751	13751	8 of the modified goal and a 200 basis point
13752	13752	9 increase for achieving 133.33% of the unmodified
13753	13753	10 goal.
13754	13754	11 (C) Notwithstanding provisions in subparagraphs
13755	13755	12 (A) and (B) of paragraph (7) of this subsection, if the
13756	13756	13 applicable annual incremental goal for an electric
13757	13757	14 utility is ever less than 0.6% of deemed average
13758	13758	15 weather normalized sales of electric power and energy
13759	13759	16 during calendar years 2014, 2015 and 2016, an
13760	13760	17 adjustment to the return on equity component of the
13761	13761	18 utility's weighted average cost of capital calculated
13762	13762	19 under subsection (d) of this Section shall be made as
13763	13763	20 follows:
13764	13764	21 (i) The return on equity component shall be
13765	13765	22 reduced by 8 basis points for each percent by
13766	13766	23 which the utility did not achieve 100% of the
13767	13767	24 applicable annual total savings requirement.
13768	13768	25 (ii) The return on equity component shall be
13769	13769	26 increased by 8 basis points for each percent by
13770	13770
13771	13771
13772	13772
13773	13773
13774	13774
13775	13775	HB3779 - 383 - LRB104 11172 AAS 21254 b
13776	13776
13777	13777
13778	13778	HB3779- 384 -LRB104 11172 AAS 21254 b HB3779 - 384 - LRB104 11172 AAS 21254 b
13779	13779	HB3779 - 384 - LRB104 11172 AAS 21254 b
13780	13780	1 which the utility exceeded 100% of the applicable
13781	13781	2 annual total savings requirement.
13782	13782	3 (iii) The return on equity component shall not
13783	13783	4 be increased or decreased by an amount greater
13784	13784	5 than 200 basis points pursuant to this
13785	13785	6 subparagraph (C).
13786	13786	7 (D) If the applicable annual incremental goal was
13787	13787	8 reduced under paragraph (1), (2), (3), or (4) of
13788	13788	9 subsection (f) of this Section, then the following
13789	13789	10 adjustments shall be made to the calculations
13790	13790	11 described in subparagraphs (A), (B), and (C) of this
13791	13791	12 paragraph (8):
13792	13792	13 (i) The calculation for determining
13793	13793	14 achievement that is at least 125% or 134%, as
13794	13794	15 applicable, of the applicable annual incremental
13795	13795	16 goal or the applicable annual total savings
13796	13796	17 requirement, as applicable, shall use the
13797	13797	18 unreduced applicable annual incremental goal to
13798	13798	19 set the value.
13799	13799	20 (ii) For the period through December 31, 2025,
13800	13800	21 the calculation for determining achievement that
13801	13801	22 is less than 125% but more than 100% of the
13802	13802	23 applicable annual incremental goal or the
13803	13803	24 applicable annual total savings requirement, as
13804	13804	25 applicable, shall use the reduced applicable
13805	13805	26 annual incremental goal to set the value for 100%
13806	13806
13807	13807
13808	13808
13809	13809
13810	13810
13811	13811	HB3779 - 384 - LRB104 11172 AAS 21254 b
13812	13812
13813	13813
13814	13814	HB3779- 385 -LRB104 11172 AAS 21254 b HB3779 - 385 - LRB104 11172 AAS 21254 b
13815	13815	HB3779 - 385 - LRB104 11172 AAS 21254 b
13816	13816	1 achievement of the goal and shall use the
13817	13817	2 unreduced goal to set the value for 125%
13818	13818	3 achievement. The 8 basis point value shall also be
13819	13819	4 modified, as necessary, so that the 200 basis
13820	13820	5 points are evenly apportioned among each
13821	13821	6 percentage point value between 100% and 125%
13822	13822	7 achievement.
13823	13823	8 (iii) For the period of January 1, 2026
13824	13824	9 through December 31, 2029 and all subsequent
13825	13825	10 4-year periods, the calculation for determining
13826	13826	11 achievement that is less than 125% or 134%, as
13827	13827	12 applicable, but more than 100% of the applicable
13828	13828	13 annual incremental goal or the applicable annual
13829	13829	14 total savings requirement, as applicable, shall
13830	13830	15 use the reduced applicable annual incremental goal
13831	13831	16 to set the value for 100% achievement of the goal
13832	13832	17 and shall use the unreduced goal to set the value
13833	13833	18 for 125% achievement. The 6 basis-point value or 8
13834	13834	19 basis-point value, as applicable, shall also be
13835	13835	20 modified, as necessary, so that the 200 basis
13836	13836	21 points are evenly apportioned among each
13837	13837	22 percentage point value between 100% and 125% or
13838	13838	23 between 100% and 134% achievement, as applicable.
13839	13839	24 (9) The utility shall submit the energy savings data
13840	13840	25 to the independent evaluator no later than 30 days after
13841	13841	26 the close of the plan year. The independent evaluator
13842	13842
13843	13843
13844	13844
13845	13845
13846	13846
13847	13847	HB3779 - 385 - LRB104 11172 AAS 21254 b
13848	13848
13849	13849
13850	13850	HB3779- 386 -LRB104 11172 AAS 21254 b HB3779 - 386 - LRB104 11172 AAS 21254 b
13851	13851	HB3779 - 386 - LRB104 11172 AAS 21254 b
13852	13852	1 shall determine the cumulative persisting annual savings
13853	13853	2 and annual incremental savings for a given plan year, as
13854	13854	3 well as an estimate of job impacts and other macroeconomic
13855	13855	4 impacts of the efficiency programs for that year, no later
13856	13856	5 than 120 days after the close of the plan year. The utility
13857	13857	6 shall submit an informational filing to the Commission no
13858	13858	7 later than 160 days after the close of the plan year that
13859	13859	8 attaches the independent evaluator's final report
13860	13860	9 identifying the cumulative persisting annual savings for
13861	13861	10 the year and calculates, under paragraph (7) or (8) of
13862	13862	11 this subsection (g), as applicable, any resulting change
13863	13863	12 to the utility's return on equity component of the
13864	13864	13 weighted average cost of capital applicable to the next
13865	13865	14 plan year beginning with the January monthly billing
13866	13866	15 period and extending through the December monthly billing
13867	13867	16 period. However, if the utility recovers the costs
13868	13868	17 incurred under this Section under paragraphs (2) and (3)
13869	13869	18 of subsection (d) of this Section, then the utility shall
13870	13870	19 not be required to submit such informational filing, and
13871	13871	20 shall instead submit the information that would otherwise
13872	13872	21 be included in the informational filing as part of its
13873	13873	22 filing under paragraph (3) of such subsection (d) that is
13874	13874	23 due on or before June 1 of each year.
13875	13875	24 For those utilities that must submit the informational
13876	13876	25 filing, the Commission may, on its own motion or by
13877	13877	26 petition, initiate an investigation of such filing,
13878	13878
13879	13879
13880	13880
13881	13881
13882	13882
13883	13883	HB3779 - 386 - LRB104 11172 AAS 21254 b
13884	13884
13885	13885
13886	13886	HB3779- 387 -LRB104 11172 AAS 21254 b HB3779 - 387 - LRB104 11172 AAS 21254 b
13887	13887	HB3779 - 387 - LRB104 11172 AAS 21254 b
13888	13888	1 provided, however, that the utility's proposed return on
13889	13889	2 equity calculation shall be deemed the final, approved
13890	13890	3 calculation on December 15 of the year in which it is filed
13891	13891	4 unless the Commission enters an order on or before
13892	13892	5 December 15, after notice and hearing, that modifies such
13893	13893	6 calculation consistent with this Section.
13894	13894	7 The adjustments to the return on equity component
13895	13895	8 described in paragraph paragraphs (7) and (8) of this
13896	13896	9 subsection (g) shall be applied as described in such
13897	13897	10 paragraphs through a separate tariff mechanism, which
13898	13898	11 shall be filed by the utility under subsections (f) and
13899	13899	12 (g) of this Section.
13900	13900	13 (9.5) The utility must demonstrate how it will ensure
13901	13901	14 that program implementation contractors and energy
13902	13902	15 efficiency installation vendors will promote workforce
13903	13903	16 equity and quality jobs.
13904	13904	17 (9.6) Utilities shall collect data necessary to ensure
13905	13905	18 compliance with paragraph (9.5) no less than quarterly and
13906	13906	19 shall communicate progress toward compliance with
13907	13907	20 paragraph (9.5) to program implementation contractors and
13908	13908	21 energy efficiency installation vendors no less than
13909	13909	22 quarterly. Utilities shall work with relevant vendors,
13910	13910	23 providing education, training, and other resources needed
13911	13911	24 to ensure compliance and, where necessary, adjusting or
13912	13912	25 terminating work with vendors that cannot assist with
13913	13913	26 compliance.
13914	13914
13915	13915
13916	13916
13917	13917
13918	13918
13919	13919	HB3779 - 387 - LRB104 11172 AAS 21254 b
13920	13920
13921	13921
13922	13922	HB3779- 388 -LRB104 11172 AAS 21254 b HB3779 - 388 - LRB104 11172 AAS 21254 b
13923	13923	HB3779 - 388 - LRB104 11172 AAS 21254 b
13924	13924	1 (10) Utilities required to implement efficiency
13925	13925	2 programs under subsections (b-5), and (b-10), and (b-16)
13926	13926	3 shall report annually to the Illinois Commerce Commission
13927	13927	4 and the General Assembly on how hiring, contracting, job
13928	13928	5 training, and other practices related to its energy
13929	13929	6 efficiency programs enhance the diversity of vendors
13930	13930	7 working on such programs. These reports must include data
13931	13931	8 on vendor and employee diversity, including data on the
13932	13932	9 implementation of paragraphs (9.5) and (9.6). If the
13933	13933	10 utility is not meeting the requirements of paragraphs
13934	13934	11 (9.5) and (9.6), the utility shall submit a plan to adjust
13935	13935	12 their activities so that they meet the requirements of
13936	13936	13 paragraphs (9.5) and (9.6) within the following year.
13937	13937	14 (h) No more than 4% of energy efficiency and
13938	13938	15 demand-response program revenue may be allocated for research,
13939	13939	16 development, or pilot deployment of new equipment or measures.
13940	13940	17 Electric utilities shall work with interested stakeholders to
13941	13941	18 formulate a plan for how these funds should be spent,
13942	13942	19 incorporate statewide approaches for these allocations, and
13943	13943	20 file a 4-year plan that demonstrates that collaboration. If a
13944	13944	21 utility files a request for modified annual energy savings
13945	13945	22 goals with the Commission, then a utility shall forgo spending
13946	13946	23 portfolio dollars on research and development proposals.
13947	13947	24 (i) When practicable, electric utilities shall incorporate
13948	13948	25 advanced metering infrastructure data into the planning,
13949	13949	26 implementation, and evaluation of energy efficiency measures
13950	13950
13951	13951
13952	13952
13953	13953
13954	13954
13955	13955	HB3779 - 388 - LRB104 11172 AAS 21254 b
13956	13956
13957	13957
13958	13958	HB3779- 389 -LRB104 11172 AAS 21254 b HB3779 - 389 - LRB104 11172 AAS 21254 b
13959	13959	HB3779 - 389 - LRB104 11172 AAS 21254 b
13960	13960	1 and programs, subject to the data privacy and confidentiality
13961	13961	2 protections of applicable law.
13962	13962	3 (j) The independent evaluator shall follow the guidelines
13963	13963	4 and use the savings set forth in Commission-approved energy
13964	13964	5 efficiency policy manuals and technical reference manuals, as
13965	13965	6 each may be updated from time to time. Until such time as
13966	13966	7 measure life values for energy efficiency measures implemented
13967	13967	8 for low-income households under subsection (c) of this Section
13968	13968	9 are incorporated into such Commission-approved manuals, the
13969	13969	10 low-income measures shall have the same measure life values
13970	13970	11 that are established for same measures implemented in
13971	13971	12 households that are not low-income households.
13972	13972	13 (k) Notwithstanding any provision of law to the contrary,
13973	13973	14 an electric utility subject to the requirements of this
13974	13974	15 Section may file a tariff cancelling an automatic adjustment
13975	13975	16 clause tariff in effect under this Section or Section 8-103,
13976	13976	17 which shall take effect no later than one business day after
13977	13977	18 the date such tariff is filed. Thereafter, the utility shall
13978	13978	19 be authorized to defer and recover its expenditures incurred
13979	13979	20 under this Section through a new tariff authorized under
13980	13980	21 subsection (d) of this Section or in the utility's next rate
13981	13981	22 case under Article IX or Section 16-108.5 of this Act, with
13982	13982	23 interest at an annual rate equal to the utility's weighted
13983	13983	24 average cost of capital as approved by the Commission in such
13984	13984	25 case. If the utility elects to file a new tariff under
13985	13985	26 subsection (d) of this Section, the utility may file the
13986	13986
13987	13987
13988	13988
13989	13989
13990	13990
13991	13991	HB3779 - 389 - LRB104 11172 AAS 21254 b
13992	13992
13993	13993
13994	13994	HB3779- 390 -LRB104 11172 AAS 21254 b HB3779 - 390 - LRB104 11172 AAS 21254 b
13995	13995	HB3779 - 390 - LRB104 11172 AAS 21254 b
13996	13996	1 tariff within 10 days after June 1, 2017 (the effective date of
13997	13997	2 Public Act 99-906), and the cost inputs to such tariff shall be
13998	13998	3 based on the projected costs to be incurred by the utility
13999	13999	4 during the calendar year in which the new tariff is filed and
14000	14000	5 that were not recovered under the tariff that was cancelled as
14001	14001	6 provided for in this subsection. Such costs shall include
14002	14002	7 those incurred or to be incurred by the utility under its
14003	14003	8 multi-year plan approved under subsections (f) and (g) of this
14004	14004	9 Section, including, but not limited to, projected capital
14005	14005	10 investment costs and projected regulatory asset balances with
14006	14006	11 correspondingly updated depreciation and amortization reserves
14007	14007	12 and expense. The Commission shall, after notice and hearing,
14008	14008	13 approve, or approve with modification, such tariff and cost
14009	14009	14 inputs no later than 75 days after the utility filed the
14010	14010	15 tariff, provided that such approval, or approval with
14011	14011	16 modification, shall be consistent with the provisions of this
14012	14012	17 Section to the extent they do not conflict with this
14013	14013	18 subsection (k). The tariff approved by the Commission shall
14014	14014	19 take effect no later than 5 days after the Commission enters
14015	14015	20 its order approving the tariff.
14016	14016	21 No later than 60 days after the effective date of the
14017	14017	22 tariff cancelling the utility's automatic adjustment clause
14018	14018	23 tariff, the utility shall file a reconciliation that
14019	14019	24 reconciles the moneys collected under its automatic adjustment
14020	14020	25 clause tariff with the costs incurred during the period
14021	14021	26 beginning June 1, 2016 and ending on the date that the electric
14022	14022
14023	14023
14024	14024
14025	14025
14026	14026
14027	14027	HB3779 - 390 - LRB104 11172 AAS 21254 b
14028	14028
14029	14029
14030	14030	HB3779- 391 -LRB104 11172 AAS 21254 b HB3779 - 391 - LRB104 11172 AAS 21254 b
14031	14031	HB3779 - 391 - LRB104 11172 AAS 21254 b
14032	14032	1 utility's automatic adjustment clause tariff was cancelled. In
14033	14033	2 the event the reconciliation reflects an under-collection, the
14034	14034	3 utility shall recover the costs as specified in this
14035	14035	4 subsection (k). If the reconciliation reflects an
14036	14036	5 over-collection, the utility shall apply the amount of such
14037	14037	6 over-collection as a one-time credit to retail customers'
14038	14038	7 bills.
14039	14039	8 (l) (Blank). For the calendar years covered by a
14040	14040	9 multi-year plan commencing after December 31, 2017,
14041	14041	10 subsections (a) through (j) of this Section do not apply to
14042	14042	11 eligible large private energy customers that have chosen to
14043	14043	12 opt out of multi-year plans consistent with this subsection
14044	14044	13 (1).
14045	14045	14 (1) For purposes of this subsection (l), "eligible
14046	14046	15 large private energy customer" means any retail customers,
14047	14047	16 except for federal, State, municipal, and other public
14048	14048	17 customers, of an electric utility that serves more than
14049	14049	18 3,000,000 retail customers, except for federal, State,
14050	14050	19 municipal and other public customers, in the State and
14051	14051	20 whose total highest 30 minute demand was more than 10,000
14052	14052	21 kilowatts, or any retail customers of an electric utility
14053	14053	22 that serves less than 3,000,000 retail customers but more
14054	14054	23 than 500,000 retail customers in the State and whose total
14055	14055	24 highest 15 minute demand was more than 10,000 kilowatts.
14056	14056	25 For purposes of this subsection (l), "retail customer" has
14057	14057	26 the meaning set forth in Section 16-102 of this Act.
14058	14058
14059	14059
14060	14060
14061	14061
14062	14062
14063	14063	HB3779 - 391 - LRB104 11172 AAS 21254 b
14064	14064
14065	14065
14066	14066	HB3779- 392 -LRB104 11172 AAS 21254 b HB3779 - 392 - LRB104 11172 AAS 21254 b
14067	14067	HB3779 - 392 - LRB104 11172 AAS 21254 b
14068	14068	1 However, for a business entity with multiple sites located
14069	14069	2 in the State, where at least one of those sites qualifies
14070	14070	3 as an eligible large private energy customer, then any of
14071	14071	4 that business entity's sites, properly identified on a
14072	14072	5 form for notice, shall be considered eligible large
14073	14073	6 private energy customers for the purposes of this
14074	14074	7 subsection (l). A determination of whether this subsection
14075	14075	8 is applicable to a customer shall be made for each
14076	14076	9 multi-year plan beginning after December 31, 2017. The
14077	14077	10 criteria for determining whether this subsection (l) is
14078	14078	11 applicable to a retail customer shall be based on the 12
14079	14079	12 consecutive billing periods prior to the start of the
14080	14080	13 first year of each such multi-year plan.
14081	14081	14 (2) Within 45 days after September 15, 2021 (the
14082	14082	15 effective date of Public Act 102-662), the Commission
14083	14083	16 shall prescribe the form for notice required for opting
14084	14084	17 out of energy efficiency programs. The notice must be
14085	14085	18 submitted to the retail electric utility 12 months before
14086	14086	19 the next energy efficiency planning cycle. However, within
14087	14087	20 120 days after the Commission's initial issuance of the
14088	14088	21 form for notice, eligible large private energy customers
14089	14089	22 may submit a form for notice to an electric utility. The
14090	14090	23 form for notice for opting out of energy efficiency
14091	14091	24 programs shall include all of the following:
14092	14092	25 (A) a statement indicating that the customer has
14093	14093	26 elected to opt out;
14094	14094
14095	14095
14096	14096
14097	14097
14098	14098
14099	14099	HB3779 - 392 - LRB104 11172 AAS 21254 b
14100	14100
14101	14101
14102	14102	HB3779- 393 -LRB104 11172 AAS 21254 b HB3779 - 393 - LRB104 11172 AAS 21254 b
14103	14103	HB3779 - 393 - LRB104 11172 AAS 21254 b
14104	14104	1 (B) the account numbers for the customer accounts
14105	14105	2 to which the opt out shall apply;
14106	14106	3 (C) the mailing address associated with the
14107	14107	4 customer accounts identified under subparagraph (B);
14108	14108	5 (D) an American Society of Heating, Refrigerating,
14109	14109	6 and Air-Conditioning Engineers (ASHRAE) level 2 or
14110	14110	7 higher audit report conducted by an independent
14111	14111	8 third-party expert identifying cost-effective energy
14112	14112	9 efficiency project opportunities that could be
14113	14113	10 invested in over the next 10 years. A retail customer
14114	14114	11 with specialized processes may utilize a self-audit
14115	14115	12 process in lieu of the ASHRAE audit;
14116	14116	13 (E) a description of the customer's plans to
14117	14117	14 reallocate the funds toward internal energy efficiency
14118	14118	15 efforts identified in the subparagraph (D) report,
14119	14119	16 including, but not limited to: (i) strategic energy
14120	14120	17 management or other programs, including descriptions
14121	14121	18 of targeted buildings, equipment and operations; (ii)
14122	14122	19 eligible energy efficiency measures; and (iii)
14123	14123	20 expected energy savings, itemized by technology. If
14124	14124	21 the subparagraph (D) audit report identifies that the
14125	14125	22 customer currently utilizes the best available energy
14126	14126	23 efficient technology, equipment, programs, and
14127	14127	24 operations, the customer may provide a statement that
14128	14128	25 more efficient technology, equipment, programs, and
14129	14129	26 operations are not reasonably available as a means of
14130	14130
14131	14131
14132	14132
14133	14133
14134	14134
14135	14135	HB3779 - 393 - LRB104 11172 AAS 21254 b
14136	14136
14137	14137
14138	14138	HB3779- 394 -LRB104 11172 AAS 21254 b HB3779 - 394 - LRB104 11172 AAS 21254 b
14139	14139	HB3779 - 394 - LRB104 11172 AAS 21254 b
14140	14140	1 satisfying this subparagraph (E); and
14141	14141	2 (F) the effective date of the opt out, which will
14142	14142	3 be the next January 1 following notice of the opt out.
14143	14143	4 (3) Upon receipt of a properly and timely noticed
14144	14144	5 request for opt out submitted by an eligible large private
14145	14145	6 energy customer, the retail electric utility shall grant
14146	14146	7 the request, file the request with the Commission and,
14147	14147	8 beginning January 1 of the following year, the opted out
14148	14148	9 customer shall no longer be assessed the costs of the plan
14149	14149	10 and shall be prohibited from participating in that 4-year
14150	14150	11 plan cycle to give the retail utility the certainty to
14151	14151	12 design program plan proposals.
14152	14152	13 (4) Upon a customer's election to opt out under
14153	14153	14 paragraphs (1) and (2) of this subsection (l) and
14154	14154	15 commencing on the effective date of said opt out, the
14155	14155	16 account properly identified in the customer's notice under
14156	14156	17 paragraph (2) shall not be subject to any cost recovery
14157	14157	18 and shall not be eligible to participate in, or directly
14158	14158	19 benefit from, compliance with energy efficiency cumulative
14159	14159	20 persisting savings requirements under subsections (a)
14160	14160	21 through (j).
14161	14161	22 (5) A utility's cumulative persisting annual savings
14162	14162	23 targets will exclude any opted out load.
14163	14163	24 (6) The request to opt out is only valid for the
14164	14164	25 requested plan cycle. An eligible large private energy
14165	14165	26 customer must also request to opt out for future energy
14166	14166
14167	14167
14168	14168
14169	14169
14170	14170
14171	14171	HB3779 - 394 - LRB104 11172 AAS 21254 b
14172	14172
14173	14173
14174	14174	HB3779- 395 -LRB104 11172 AAS 21254 b HB3779 - 395 - LRB104 11172 AAS 21254 b
14175	14175	HB3779 - 395 - LRB104 11172 AAS 21254 b
14176	14176	1 plan cycles, otherwise the customer will be included in
14177	14177	2 the future energy plan cycle.
14178	14178	3 (m) Notwithstanding the requirements of this Section, as
14179	14179	4 part of a proceeding to approve a multi-year plan under
14180	14180	5 subsections (f) and (g) of this Section if the multi-year plan
14181	14181	6 has been designed to maximize savings, but does not meet the
14182	14182	7 cost cap limitations of this Section, the Commission shall
14183	14183	8 reduce the amount of energy efficiency measures implemented
14184	14184	9 for any single year, and whose costs are recovered under
14185	14185	10 subsection (d) of this Section, by an amount necessary to
14186	14186	11 limit the estimated average net increase due to the cost of the
14187	14187	12 measures to no more than
14188	14188	13 (1) 3.5% for each of the 4 years beginning January 1,
14189	14189	14 2018,
14190	14190	15 (2) (blank),
14191	14191	16 (3) 4% for each of the 4 years beginning January 1,
14192	14192	17 2022,
14193	14193	18 (3.5) 4.25% for 2026;
14194	14194	19 (4) 4.25% for electric utilities that serve more than
14195	14195	20 3,000,000 retail customers in the State, and 5.19% for
14196	14196	21 electric utilities with less than 3,000,000 retail
14197	14197	22 customers but more than 500,000 retail customers in the
14198	14198	23 state, for the 3 4 years beginning January 1, 2027 2026,
14199	14199	24 and
14200	14200	25 (5) the percentage specified in paragraph (4) 4.25%
14201	14201	26 plus an increase sufficient to account for the rate of
14202	14202
14203	14203
14204	14204
14205	14205
14206	14206
14207	14207	HB3779 - 395 - LRB104 11172 AAS 21254 b
14208	14208
14209	14209
14210	14210	HB3779- 396 -LRB104 11172 AAS 21254 b HB3779 - 396 - LRB104 11172 AAS 21254 b
14211	14211	HB3779 - 396 - LRB104 11172 AAS 21254 b
14212	14212	1 inflation between January 1, 2027 2026 and January 1 of
14213	14213	2 the first year of each subsequent 4-year plan cycle,
14214	14214	3 of the average amount paid per kilowatthour by residential
14215	14215	4 eligible retail customers during calendar year 2015 for plans
14216	14216	5 in effect through 2026 and calendar year 2023 for plans
14217	14217	6 commencing in 2027 and beyond. An electric utility may plan to
14218	14218	7 spend up to 10% more in any year during an applicable
14219	14219	8 multi-year plan period to cost-effectively achieve additional
14220	14220	9 savings so long as the average over the applicable multi-year
14221	14221	10 plan period does not exceed the percentages defined in items
14222	14222	11 (1) through (5). To determine the total amount that may be
14223	14223	12 spent by an electric utility in any single year, the
14224	14224	13 applicable percentage of the average amount paid per
14225	14225	14 kilowatthour shall be multiplied by the total amount of energy
14226	14226	15 delivered by such electric utility in the calendar year 2015
14227	14227	16 for plans in effect through 2026 and calendar year 2023 for
14228	14228	17 plans commencing in 2027 and beyond, adjusted to reflect the
14229	14229	18 proportion of the utility's load attributable to customers
14230	14230	19 that have opted out of subsections (a) through (j) of this
14231	14231	20 Section under subsection (l) of this Section. For purposes of
14232	14232	21 this subsection (m), the amount paid per kilowatthour
14233	14233	22 includes, without limitation, estimated amounts paid for
14234	14234	23 supply, transmission, distribution, surcharges, and add-on
14235	14235	24 taxes. For purposes of this Section, "eligible retail
14236	14236	25 customers" shall have the meaning set forth in Section
14237	14237	26 16-111.5 of this Act. Once the Commission has approved a plan
14238	14238
14239	14239
14240	14240
14241	14241
14242	14242
14243	14243	HB3779 - 396 - LRB104 11172 AAS 21254 b
14244	14244
14245	14245
14246	14246	HB3779- 397 -LRB104 11172 AAS 21254 b HB3779 - 397 - LRB104 11172 AAS 21254 b
14247	14247	HB3779 - 397 - LRB104 11172 AAS 21254 b
14248	14248	1 under subsections (f) and (g) of this Section, no subsequent
14249	14249	2 rate impact determinations shall be made.
14250	14250	3 (n) A utility shall take advantage of the efficiencies
14251	14251	4 available through existing Illinois Home Weatherization
14252	14252	5 Assistance Program infrastructure and services, such as
14253	14253	6 enrollment, marketing, quality assurance and implementation,
14254	14254	7 which can reduce the need for similar services at a lower cost
14255	14255	8 than utility-only programs, subject to capacity constraints at
14256	14256	9 community action agencies, for both single-family and
14257	14257	10 multifamily weatherization services, to the extent Illinois
14258	14258	11 Home Weatherization Assistance Program community action
14259	14259	12 agencies provide multifamily services. A utility's plan shall
14260	14260	13 demonstrate that in formulating annual weatherization budgets,
14261	14261	14 it has sought input and coordination with community action
14262	14262	15 agencies regarding agencies' capacity to expand and maximize
14263	14263	16 Illinois Home Weatherization Assistance Program delivery using
14264	14264	17 the ratepayer dollars collected under this Section.
14265	14265	18 (Source: P.A. 102-662, eff. 9-15-21; 103-154, eff. 6-30-23.)
14266	14266	19 (220 ILCS 5/8-104B new)
14267	14267	20 Sec. 8-104B. Gas energy efficiency.
14268	14268	21 (a) As used in this Section:
14269	14269	22 "Benefit-cost ratio" means the ratio of the net present
14270	14270	23 value of the total benefits of the measures to the net present
14271	14271	24 value of the total costs as calculated over the lifetime of the
14272	14272	25 measures.
14273	14273
14274	14274
14275	14275
14276	14276
14277	14277
14278	14278	HB3779 - 397 - LRB104 11172 AAS 21254 b
14279	14279
14280	14280
14281	14281	HB3779- 398 -LRB104 11172 AAS 21254 b HB3779 - 398 - LRB104 11172 AAS 21254 b
14282	14282	HB3779 - 398 - LRB104 11172 AAS 21254 b
14283	14283	1 "Cost-effective measure" means a measure that satisfies
14284	14284	2 the total resource cost test.
14285	14285	3 "Energy efficiency measure" means a measure that reduces
14286	14286	4 (i) the total Btus of electricity and natural gas and other
14287	14287	5 utility-delivered gaseous fuels needed to meet an end use or
14288	14288	6 end uses and (ii) the amount of natural gas and other
14289	14289	7 utility-delivered gaseous fuels consumed on site, at the home
14290	14290	8 or business facility, to meet an end use or end uses.
14291	14291	9 "Total resource cost test" has the same meaning as set
14292	14292	10 forth in Section 1-10 of the Illinois Power Agency Act.
14293	14293	11 (b) It is the policy of the State for gas utilities to be
14294	14294	12 required to use cost-effective energy efficiency measures to
14295	14295	13 reduce delivery load. Requiring investment in cost-effective
14296	14296	14 energy efficiency measures will reduce direct and indirect
14297	14297	15 costs to consumers by decreasing environmental impacts,
14298	14298	16 reducing the amount of natural gas and other utility-delivered
14299	14299	17 gaseous fuels that need to be purchased, and avoiding or
14300	14300	18 delaying the need for new transmission, distribution, storage,
14301	14301	19 and other related infrastructure. Moreover, the public
14302	14302	20 interest is served by allowing gas utilities to recover costs
14303	14303	21 for reasonably and prudently incurred expenditures for energy
14304	14304	22 efficiency measures.
14305	14305	23 (c) This Section applies to all gas distribution utilities
14306	14306	24 in the State and supersedes Section 8-104 beginning January 1,
14307	14307	25 2027.
14308	14308	26 (d) Natural gas utilities shall implement cost-effective
14309	14309
14310	14310
14311	14311
14312	14312
14313	14313
14314	14314	HB3779 - 398 - LRB104 11172 AAS 21254 b
14315	14315
14316	14316
14317	14317	HB3779- 399 -LRB104 11172 AAS 21254 b HB3779 - 399 - LRB104 11172 AAS 21254 b
14318	14318	HB3779 - 399 - LRB104 11172 AAS 21254 b
14319	14319	1 energy efficiency measures to achieve all of the following
14320	14320	2 requirements:
14321	14321	3 (1) Total incremental annual savings shall be equal to
14322	14322	4 at least 0.6% of annual sales to distribution customers in
14323	14323	5 2027, 0.8% of such sales in 2028 and at least 1% of such
14324	14324	6 sales in 2029 and each subsequent year. For the purposes
14325	14325	7 of this Section, "incremental annual savings" means the
14326	14326	8 total gas savings from all measures installed in a
14327	14327	9 calendar year that will be realized within 12 months of
14328	14328	10 each measure's installation. For the purpose of
14329	14329	11 calculating savings as a percent of sales to distribution
14330	14330	12 customers for a given program year, the denominator of
14331	14331	13 sales to distribution customers shall be annual average
14332	14332	14 sales over the second, third, and fourth full calendar
14333	14333	15 years prior to the beginning of the program year.
14334	14334	16 (2) The savings achieved must have an average life of
14335	14335	17 at least 12 years. In no event can more than one-fifth of
14336	14336	18 the incremental annual savings counted towards a utility's
14337	14337	19 annual savings goal in any given year be derived from
14338	14338	20 efficiency measures with average savings lives of less
14339	14339	21 than 5 years. Average savings life is defined as the
14340	14340	22 lifetime savings that would be realized as a result of a
14341	14341	23 utility's efficiency programs divided by the incremental
14342	14342	24 annual savings such programs produce. Average savings
14343	14343	25 lives may be shorter than the average operational lives of
14344	14344	26 measures installed if the measures do not produce savings
14345	14345
14346	14346
14347	14347
14348	14348
14349	14349
14350	14350	HB3779 - 399 - LRB104 11172 AAS 21254 b
14351	14351
14352	14352
14353	14353	HB3779- 400 -LRB104 11172 AAS 21254 b HB3779 - 400 - LRB104 11172 AAS 21254 b
14354	14354	HB3779 - 400 - LRB104 11172 AAS 21254 b
14355	14355	1 in every year in which they operate or if the savings that
14356	14356	2 measures produce decline during their operational lives.
14357	14357	3 (3) Except as provided in subsection (A) of this
14358	14358	4 Section, savings may not be applied toward achievement of
14359	14359	5 utility savings goals if the savings arise from the
14360	14360	6 installation of efficient new gas furnaces, gas boilers,
14361	14361	7 gas water heaters, or other gas-consuming equipment in a
14362	14362	8 residential building, such as a single-family,
14363	14363	9 individually-metered multifamily, or master-metered
14364	14364	10 multifamily building.
14365	14365	11 (A) Savings may be applied toward achievement of
14366	14366	12 utility savings goals if the savings arise from the
14367	14367	13 installation of gas furnaces through income-eligible
14368	14368	14 programs when it is determined the existing furnace is
14369	14369	15 no longer working, requires significant annual
14370	14370	16 maintenance costs in order to remain operational, or
14371	14371	17 is creating a health and safety hazard.
14372	14372	18 (4) At least 67% of the entire budget for efficiency
14373	14373	19 programs shall be spent on energy efficiency measures that
14374	14374	20 reduce space heating needs through improvements to the
14375	14375	21 efficiency of building envelopes, including, but not
14376	14376	22 limited to, insulation measures and efficient windows and
14377	14377	23 energy efficiency measures that reduce air leakage through
14378	14378	24 improvements to systems for distributing heat, including,
14379	14379	25 but not limited to, duct leakage reduction, duct
14380	14380	26 insulation, or pipe insulation in buildings or through
14381	14381
14382	14382
14383	14383
14384	14384
14385	14385
14386	14386	HB3779 - 400 - LRB104 11172 AAS 21254 b
14387	14387
14388	14388
14389	14389	HB3779- 401 -LRB104 11172 AAS 21254 b HB3779 - 401 - LRB104 11172 AAS 21254 b
14390	14390	HB3779 - 401 - LRB104 11172 AAS 21254 b
14391	14391	1 improved heating systems controls, including, but not
14392	14392	2 limited to, advanced thermostats and demand control
14393	14393	3 ventilation. Spending on efficient furnaces, efficient
14394	14394	4 boilers, or other efficient heating systems is permitted
14395	14395	5 within business efficiency programs but does not count
14396	14396	6 toward this minimum requirement for spending on building
14397	14397	7 envelope, heating distribution, and control efficiencies.
14398	14398	8 Spending on income-qualified building envelope measures,
14399	14399	9 heating distribution system measures, and heating controls
14400	14400	10 does count toward this requirement. The portion of portfolio
14401	14401	11 spending on program marketing, training of installers, audits
14402	14402	12 of buildings, inspections of work performed, and other
14403	14403	13 administrative and technical expenses that are clearly tied to
14404	14404	14 promotion or installation of building envelope or heating
14405	14405	15 distribution system measures shall count toward this
14406	14406	16 requirement. If this minimum requirement is not met, any
14407	14407	17 performance incentive earned under subsection (h) should be
14408	14408	18 reduced by the percentage point level of shortfall in meeting
14409	14409	19 this requirement.
14410	14410	20 (5) The portion of the entire budget for efficiency
14411	14411	21 programs that is spent on efficiency measures for
14412	14412	22 income-qualified households shall be the greater of 25% or
14413	14413	23 5 percentage points more than the proportion of total
14414	14414	24 residential and business customer gas sales going to
14415	14415	25 income-qualified households. For purposes of this Section,
14416	14416	26 households at or below 80% of area median income are
14417	14417
14418	14418
14419	14419
14420	14420
14421	14421
14422	14422	HB3779 - 401 - LRB104 11172 AAS 21254 b
14423	14423
14424	14424
14425	14425	HB3779- 402 -LRB104 11172 AAS 21254 b HB3779 - 402 - LRB104 11172 AAS 21254 b
14426	14426	HB3779 - 402 - LRB104 11172 AAS 21254 b
14427	14427	1 income-qualified. At least 80% of spending on measures in
14428	14428	2 programs targeted at income-qualified households shall be
14429	14429	3 delivered through whole building weatherization programs
14430	14430	4 and spent on measures that reduce space heating needs
14431	14431	5 through improvements to the building envelope, heating
14432	14432	6 distribution systems, or heating controls. The utilities
14433	14433	7 shall invest in health and safety measures appropriate and
14434	14434	8 necessary for comprehensively weatherizing the homes and
14435	14435	9 multifamily buildings of income-qualified households, with
14436	14436	10 up to 15% of income-qualified program spending made
14437	14437	11 available for such purposes. The ratio of spending on
14438	14438	12 efficiency programs targeted at multifamily buildings of
14439	14439	13 income-qualified households to spending on energy
14440	14440	14 efficiency programs targeted at single-family buildings of
14441	14441	15 income-qualified households shall be designed to achieve
14442	14442	16 levels of savings from each building type that are
14443	14443	17 approximately proportional to the magnitude of
14444	14444	18 cost-effective lifetime savings potential in each building
14445	14445	19 type. The gas utilities shall participate in a Low-Income
14446	14446	20 Energy Efficiency Accountability Committee as established
14447	14447	21 in Section 8-103B.
14448	14448	22 Gas utilities must conduct customer outreach and education
14449	14449	23 efforts in equity investment eligible communities in order to
14450	14450	24 provide notice of and explanations concerning the following
14451	14451	25 types of programs:
14452	14452	26 (A) energy efficiency programs, the Illinois Solar
14453	14453
14454	14454
14455	14455
14456	14456
14457	14457
14458	14458	HB3779 - 402 - LRB104 11172 AAS 21254 b
14459	14459
14460	14460
14461	14461	HB3779- 403 -LRB104 11172 AAS 21254 b HB3779 - 403 - LRB104 11172 AAS 21254 b
14462	14462	HB3779 - 403 - LRB104 11172 AAS 21254 b
14463	14463	1 for All Program, and whole home retrofit programs that
14464	14464	2 reduce natural gas usage;
14465	14465	3 (B) income-qualified financial assistance
14466	14466	4 programs, including rebate programs from the federal
14467	14467	5 government; and
14468	14468	6 (C) general education programs designed to explain
14469	14469	7 utility bills and the decisions customers can make to
14470	14470	8 lower energy usage.
14471	14471	9 These outreach and education efforts must be brought to
14472	14472	10 communities in a diversity of ways, must be created with input
14473	14473	11 from members of the communities, and must be provided through,
14474	14474	12 among other things:
14475	14475	13 (i) information on customers' bills in the
14476	14476	14 main languages spoken in the communities;
14477	14477	15 (ii) a quarterly posting in local newspapers
14478	14478	16 that cover the service area;
14479	14479	17 (iii) a dedicated section on the
14480	14480	18 investor-owned utility's website; and
14481	14481	19 (iv) in-person and virtual educational
14482	14482	20 sessions that take place in the income-qualified
14483	14483	21 and Justice40 community, provide food and child
14484	14484	22 care for participating customers, and are
14485	14485	23 codesigned with interested community-based
14486	14486	24 organization representatives.
14487	14487	25 (6) Implementation of energy efficiency measures and
14488	14488	26 programs targeted at income-qualified households shall be
14489	14489
14490	14490
14491	14491
14492	14492
14493	14493
14494	14494	HB3779 - 403 - LRB104 11172 AAS 21254 b
14495	14495
14496	14496
14497	14497	HB3779- 404 -LRB104 11172 AAS 21254 b HB3779 - 404 - LRB104 11172 AAS 21254 b
14498	14498	HB3779 - 404 - LRB104 11172 AAS 21254 b
14499	14499	1 contracted, when practicable, to independent third parties
14500	14500	2 that have demonstrated the capability of serving those
14501	14501	3 households, with a preference for not-for-profit entities
14502	14502	4 and government agencies that have existing relationships
14503	14503	5 with, experience serving, or working directly within and
14504	14504	6 alongside income-qualified communities in the State. Each
14505	14505	7 gas utility shall develop and implement reporting
14506	14506	8 procedures that address and assist in determining the
14507	14507	9 amount of energy savings that can be applied to the
14508	14508	10 income-qualified procurement and expenditure requirements
14509	14509	11 set forth in this paragraph.
14510	14510	12 (7) A minimum of 10% of the utility's entire portfolio
14511	14511	13 funding level for a given year shall be used to procure
14512	14512	14 cost-effective energy efficiency measures from units of
14513	14513	15 local government, municipal corporations, school
14514	14514	16 districts, public housing, community college districts,
14515	14515	17 and nonprofit-owned buildings as long as a minimum
14516	14516	18 percentage of available funds shall be used to procure
14517	14517	19 energy efficiency from public housing, which percentage
14518	14518	20 shall be, at a minimum, equal to public housing's share of
14519	14519	21 public building energy consumption. Spending on public
14520	14520	22 housing may count toward minimum spending requirements on
14521	14521	23 efficiency improvements for income-qualified households.
14522	14522	24 (e) Notwithstanding any other provision of law, a utility
14523	14523	25 providing approved energy efficiency measures in the State may
14524	14524	26 recover all reasonable and prudently incurred costs of those
14525	14525
14526	14526
14527	14527
14528	14528
14529	14529
14530	14530	HB3779 - 404 - LRB104 11172 AAS 21254 b
14531	14531
14532	14532
14533	14533	HB3779- 405 -LRB104 11172 AAS 21254 b HB3779 - 405 - LRB104 11172 AAS 21254 b
14534	14534	HB3779 - 405 - LRB104 11172 AAS 21254 b
14535	14535	1 measures from its retail customers. However, nothing in this
14536	14536	2 subsection permits the double recovery of such costs from
14537	14537	3 customers.
14538	14538	4 (f) Beginning in 2026, each gas utility shall file an
14539	14539	5 energy efficiency plan with the Commission to meet the energy
14540	14540	6 efficiency standards in subsection (d) for the next applicable
14541	14541	7 multiyear period beginning January 1 of the year following the
14542	14542	8 filing, according to the schedule set forth in paragraphs (1)
14543	14543	9 through (4). If a utility does not file such a plan on or
14544	14544	10 before the applicable filing deadline for the plan, the
14545	14545	11 utility shall be liable for a civil penalty of $100,000 per day
14546	14546	12 until the plan is filed.
14547	14547	13 (1) The energy efficiency plans of gas utilities that
14548	14548	14 were approved by the Commission for calendar years 2022
14549	14549	15 through 2025, including any stipulated agreements between
14550	14550	16 the utility and other parties that were approved by the
14551	14551	17 Commission, shall continue to be in force through calendar
14552	14552	18 year 2026. The utilities' savings goals for 2026 shall be
14553	14553	19 equal to the average annual savings goal approved for the
14554	14554	20 years 2022 through 2025.
14555	14555	21 (2) No later than March 1, 2026, each gas utility
14556	14556	22 shall file a 3-year energy efficiency plan that takes
14557	14557	23 effect on January 1, 2027 and is designed to achieve,
14558	14558	24 through implementation of emergency efficiency measures,
14559	14559	25 the incremental annual savings goals, minimum average
14560	14560	26 savings life, and other requirements specified in
14561	14561
14562	14562
14563	14563
14564	14564
14565	14565
14566	14566	HB3779 - 405 - LRB104 11172 AAS 21254 b
14567	14567
14568	14568
14569	14569	HB3779- 406 -LRB104 11172 AAS 21254 b HB3779 - 406 - LRB104 11172 AAS 21254 b
14570	14570	HB3779 - 406 - LRB104 11172 AAS 21254 b
14571	14571	1 paragraphs (1) through (7) of subsection (d). An energy
14572	14572	2 efficiency plan submitted by a gas utility under this
14573	14573	3 paragraph supersedes any energy efficiency plan previous
14574	14574	4 approved by the Commission for calendar year 2027 or
14575	14575	5 thereafter.
14576	14576	6 (3) Beginning in 2029 and every 4 years thereafter,
14577	14577	7 each gas utility shall file by no later than March 1 of the
14578	14578	8 applicable year, a 4-year energy efficiency plan that
14579	14579	9 takes effect on the following January 1 and is designed to
14580	14580	10 achieve, through implementation of energy efficiency
14581	14581	11 measures, the incremental annual savings goals, minimum
14582	14582	12 average savings life, and other requirements specified in
14583	14583	13 paragraphs (1) through (7) of subsection (d). However, the
14584	14584	14 incremental annual savings goals may be reduced if the
14585	14585	15 plan's analysis and forecasts of the utility's ability to
14586	14586	16 acquire energy savings demonstrate by clear and convincing
14587	14587	17 evidence and through independent analysis that achievement
14588	14588	18 of such goals is not cost-effective. In no event may
14589	14589	19 incremental annual savings goals for any year be reduced
14590	14590	20 to levels below (i) those actually achieved in the
14591	14591	21 calendar year before the plan filing, (ii) those forecast
14592	14592	22 to be achieved in the calendar year in which the plan
14593	14593	23 filing is made, or (iii) 0.75% of sales. The Commission
14594	14594	24 shall review any proposed goal reduction as part of its
14595	14595	25 review and approval of the utility's proposed plan.
14596	14596	26 (4) Each utility's plan shall set forth the utility's
14597	14597
14598	14598
14599	14599
14600	14600
14601	14601
14602	14602	HB3779 - 406 - LRB104 11172 AAS 21254 b
14603	14603
14604	14604
14605	14605	HB3779- 407 -LRB104 11172 AAS 21254 b HB3779 - 407 - LRB104 11172 AAS 21254 b
14606	14606	HB3779 - 407 - LRB104 11172 AAS 21254 b
14607	14607	1 proposals to meet the energy efficiency standards
14608	14608	2 identified in subsection (d). The Commission shall seek
14609	14609	3 public comment on each plan that takes effect on or after
14610	14610	4 January 1, 2027 and shall issue an order approving or
14611	14611	5 disapproving the plan within 6 months after its
14612	14612	6 submission. If the Commission disapproves a plan, the
14613	14613	7 Commission shall, within 30 days, describe in detail the
14614	14614	8 reasons for the disapproval and describe a path by which
14615	14615	9 the utility may file a revised draft of the plan to address
14616	14616	10 the Commission's concerns satisfactorily. If the utility
14617	14617	11 does not refile with the Commission within 60 days, the
14618	14618	12 utility shall be subject to civil penalties at a rate of
14619	14619	13 $100,000 per day until the plan is refiled. This process
14620	14620	14 shall continue, and penalties shall accrue, until the
14621	14621	15 utility has successfully filed a portfolio of energy
14622	14622	16 efficiency measures. Penalties shall be deposited into the
14623	14623	17 Energy Efficiency Trust Fund.
14624	14624	18 (g) In submitting proposed plans and funding levels under
14625	14625	19 subsection (f) to meet the savings goals identified in
14626	14626	20 subsection (d), the utility shall:
14627	14627	21 (1) demonstrate that its proposed energy efficiency
14628	14628	22 measures will achieve the requirements that are identified
14629	14629	23 in subsection (d);
14630	14630	24 (2) demonstrate consideration of program options for
14631	14631	25 supporting efforts to improve compliance with new building
14632	14632	26 codes, appliance standards, and municipal regulations as
14633	14633
14634	14634
14635	14635
14636	14636
14637	14637
14638	14638	HB3779 - 407 - LRB104 11172 AAS 21254 b
14639	14639
14640	14640
14641	14641	HB3779- 408 -LRB104 11172 AAS 21254 b HB3779 - 408 - LRB104 11172 AAS 21254 b
14642	14642	HB3779 - 408 - LRB104 11172 AAS 21254 b
14643	14643	1 potentially cost-effective means of acquiring energy
14644	14644	2 savings to count toward energy savings goals;
14645	14645	3 (3) demonstrate that its overall portfolio of measures
14646	14646	4 and programs, not including income-qualified programs
14647	14647	5 described in subsection (d), is cost-effective using the
14648	14648	6 total resource cost test and represents a diverse cross
14649	14649	7 section of opportunities for customers of all rate classes
14650	14650	8 to participate in programs. Individual measures need not
14651	14651	9 be cost-effective;
14652	14652	10 (4) demonstrate that the utility's plan integrates the
14653	14653	11 delivery of energy efficiency programs with electric
14654	14654	12 efficiency programs, programs promoting demand response,
14655	14655	13 and other efforts to address bill payment issues,
14656	14656	14 including, but not limited to, the Low Income Home Energy
14657	14657	15 Assistance Program and the Percentage of Income Payment
14658	14658	16 Plans;
14659	14659	17 (5) include a proposed or revised cost-recovery
14660	14660	18 mechanism to fund the proposed energy efficiency measures
14661	14661	19 and ensure the recovery of the prudently and reasonably
14662	14662	20 incurred costs of Commission-approved programs;
14663	14663	21 (6) provide, using not more than 3% of portfolio
14664	14664	22 resources in any given year, an annual independent
14665	14665	23 evaluation of the performance and cost-effectiveness of
14666	14666	24 the utility's portfolio of measures and programs;
14667	14667	25 (7) demonstrate how it will ensure that program
14668	14668	26 implementation contractors and energy efficiency
14669	14669
14670	14670
14671	14671
14672	14672
14673	14673
14674	14674	HB3779 - 408 - LRB104 11172 AAS 21254 b
14675	14675
14676	14676
14677	14677	HB3779- 409 -LRB104 11172 AAS 21254 b HB3779 - 409 - LRB104 11172 AAS 21254 b
14678	14678	HB3779 - 409 - LRB104 11172 AAS 21254 b
14679	14679	1 installation vendors will promote workforce equity and
14680	14680	2 quality jobs. Utilities shall collect, and make publicly
14681	14681	3 available at least quarterly, data necessary to
14682	14682	4 demonstrate how efforts are advancing workforce equity.
14683	14683	5 Utilities shall work with relevant vendors providing
14684	14684	6 education, training, and other resources needed to ensure
14685	14685	7 compliance and, where necessary, adjusting or terminating
14686	14686	8 work with vendors that cannot assist with compliance; and
14687	14687	9 (8) include any plans for research, development, or
14688	14688	10 pilot deployment of new measures or program approaches.
14689	14689	11 For utilities with unmodified savings goals, no more than
14690	14690	12 4% of energy efficiency portfolio spending may be
14691	14691	13 allocated for such purposes. For utilities with modified
14692	14692	14 savings goals, no more than 2% of energy efficiency
14693	14693	15 portfolio spending may be allocated for such purposes.
14694	14694	16 Utilities shall work with interested stakeholders to
14695	14695	17 formulate a plan for how any proposed funds should be
14696	14696	18 spent, incorporate statewide approaches for these
14697	14697	19 allocations whenever such approaches would be more
14698	14698	20 effective or cost-efficient, and demonstrate such
14699	14699	21 collaboration in the utilities' plans.
14700	14700	22 (h) Each gas utility shall be eligible to earn a
14701	14701	23 shareholder incentive for effective implementation of its
14702	14702	24 efficiency programs. The incentive shall be tied to each
14703	14703	25 utility's annual energy efficiency spending and its savings.
14704	14704	26 There shall be no incentive if the independent evaluator
14705	14705
14706	14706
14707	14707
14708	14708
14709	14709
14710	14710	HB3779 - 409 - LRB104 11172 AAS 21254 b
14711	14711
14712	14712
14713	14713	HB3779- 410 -LRB104 11172 AAS 21254 b HB3779 - 410 - LRB104 11172 AAS 21254 b
14714	14714	HB3779 - 410 - LRB104 11172 AAS 21254 b
14715	14715	1 determines the utility either (i) did not fully meet all of the
14716	14716	2 requirements specified in paragraphs (3) through (7) of
14717	14717	3 subsection (d) or (ii) failed to achieve at least 90% of its
14718	14718	4 lifetime savings goal. If a utility meets all of the
14719	14719	5 requirements specified in paragraphs (3) through (7) of
14720	14720	6 subsection (d), it can earn an incentive equal to 0.4% of total
14721	14721	7 annual efficiency spending in the year being evaluated for
14722	14722	8 every one percentage point above 90% of its lifetime savings
14723	14723	9 goal that it achieves for that year, with a maximum incentive
14724	14724	10 of 12% for achieving 120% of its lifetime savings goal. For
14725	14725	11 purposes of this section, a utility's lifetime savings goal is
14726	14726	12 the product of its incremental savings goal specified in
14727	14727	13 paragraph (1) of subsection (d) and the minimum average
14728	14728	14 savings life specified in paragraph (2) of subsection (d).
14729	14729	15 (i) The utility shall submit energy savings data to the
14730	14730	16 independent evaluator no later than 30 days after the close of
14731	14731	17 the plan year. The independent evaluator shall determine the
14732	14732	18 incremental annual savings and average savings life, as well
14733	14733	19 as an estimate of the job impacts and other macroeconomic
14734	14734	20 impacts of the efficiency programs for that year, achieved no
14735	14735	21 later than 120 days after the close of the plan year. The
14736	14736	22 utility shall submit an informational filing to the Commission
14737	14737	23 no later than 160 days after the close of the plan year that
14738	14738	24 attaches the independent evaluator's final report identifying
14739	14739	25 the incremental annual savings for the year, identifying
14740	14740	26 average savings life for the year, documenting compliance with
14741	14741
14742	14742
14743	14743
14744	14744
14745	14745
14746	14746	HB3779 - 410 - LRB104 11172 AAS 21254 b
14747	14747
14748	14748
14749	14749	HB3779- 411 -LRB104 11172 AAS 21254 b HB3779 - 411 - LRB104 11172 AAS 21254 b
14750	14750	HB3779 - 411 - LRB104 11172 AAS 21254 b
14751	14751	1 other requirements in subsection (d), and, as applicable, the
14752	14752	2 magnitude of any shareholder incentive which the utility has
14753	14753	3 earned.
14754	14754	4 (j) Gas utilities shall report annually to the Commission
14755	14755	5 and General Assembly on how hiring, contracting, job training,
14756	14756	6 and other practices related to its energy efficiency programs
14757	14757	7 enhance the diversity of vendors working on such programs.
14758	14758	8 These reports must include data on vendor and employee
14759	14759	9 diversity.
14760	14760	10 (k) The independent evaluator shall follow the guidelines
14761	14761	11 and use the savings set forth in Commission-approved energy
14762	14762	12 efficiency policy manuals and technical reference manuals, as
14763	14763	13 each may be updated from time to time. Until measure life
14764	14764	14 values for energy efficiency measures implemented for
14765	14765	15 income-qualified households are separately incorporated into
14766	14766	16 such Commission-approved manuals, the income-qualified
14767	14767	17 measures shall have the same measure life values that are
14768	14768	18 established for the same measures implemented in households
14769	14769	19 that are not income-qualified households.
14770	14770	20 (220 ILCS 5/8-406) (from Ch. 111 2/3, par. 8-406)
14771	14771	21 Sec. 8-406. Certificate of public convenience and
14772	14772	22 necessity.
14773	14773	23 (a) No public utility not owning any city or village
14774	14774	24 franchise nor engaged in performing any public service or in
14775	14775	25 furnishing any product or commodity within this State as of
14776	14776
14777	14777
14778	14778
14779	14779
14780	14780
14781	14781	HB3779 - 411 - LRB104 11172 AAS 21254 b
14782	14782
14783	14783
14784	14784	HB3779- 412 -LRB104 11172 AAS 21254 b HB3779 - 412 - LRB104 11172 AAS 21254 b
14785	14785	HB3779 - 412 - LRB104 11172 AAS 21254 b
14786	14786	1 July 1, 1921 and not possessing a certificate of public
14787	14787	2 convenience and necessity from the Illinois Commerce
14788	14788	3 Commission, the State Public Utilities Commission, or the
14789	14789	4 Public Utilities Commission, at the time Public Act 84-617
14790	14790	5 goes into effect (January 1, 1986), shall transact any
14791	14791	6 business in this State until it shall have obtained a
14792	14792	7 certificate from the Commission that public convenience and
14793	14793	8 necessity require the transaction of such business. A
14794	14794	9 certificate of public convenience and necessity requiring the
14795	14795	10 transaction of public utility business in any area of this
14796	14796	11 State shall include authorization to the public utility
14797	14797	12 receiving the certificate of public convenience and necessity
14798	14798	13 to construct such plant, equipment, property, or facility as
14799	14799	14 is provided for under the terms and conditions of its tariff
14800	14800	15 and as is necessary to provide utility service and carry out
14801	14801	16 the transaction of public utility business by the public
14802	14802	17 utility in the designated area.
14803	14803	18 (b) No public utility shall begin the construction of any
14804	14804	19 new plant, equipment, property, or facility which is not in
14805	14805	20 substitution of any existing plant, equipment, property, or
14806	14806	21 facility, or any extension or alteration thereof or in
14807	14807	22 addition thereto, unless and until it shall have obtained from
14808	14808	23 the Commission a certificate that public convenience and
14809	14809	24 necessity require such construction. Whenever after a hearing
14810	14810	25 the Commission determines that any new construction or the
14811	14811	26 transaction of any business by a public utility will promote
14812	14812
14813	14813
14814	14814
14815	14815
14816	14816
14817	14817	HB3779 - 412 - LRB104 11172 AAS 21254 b
14818	14818
14819	14819
14820	14820	HB3779- 413 -LRB104 11172 AAS 21254 b HB3779 - 413 - LRB104 11172 AAS 21254 b
14821	14821	HB3779 - 413 - LRB104 11172 AAS 21254 b
14822	14822	1 the public convenience and is necessary thereto, it shall have
14823	14823	2 the power to issue certificates of public convenience and
14824	14824	3 necessity. The Commission shall determine that proposed
14825	14825	4 construction will promote the public convenience and necessity
14826	14826	5 only if the utility demonstrates: (1) that the proposed
14827	14827	6 construction is necessary to provide adequate, reliable, and
14828	14828	7 efficient service to its customers and is the least-cost means
14829	14829	8 of satisfying the service needs of its customers or that the
14830	14830	9 proposed construction will promote the development of an
14831	14831	10 effectively competitive electricity market that operates
14832	14832	11 efficiently, is equitable to all customers, and is the least
14833	14833	12 cost means of satisfying those objectives; (2) that the
14834	14834	13 utility is capable of efficiently managing and supervising the
14835	14835	14 construction process and has taken sufficient action to ensure
14836	14836	15 adequate and efficient construction and supervision thereof;
14837	14837	16 and (3) that the utility is capable of financing the proposed
14838	14838	17 construction without significant adverse financial
14839	14839	18 consequences for the utility or its customers; and (4) that
14840	14840	19 the public utility plans to implement grid enhancing
14841	14841	20 technologies maximizing the value of the project, such as but
14842	14842	21 not limited to advanced power flow control, topology
14843	14843	22 optimization, and dynamic line rating, unless the public
14844	14844	23 utility demonstrates grid enhancing technologies are not cost
14845	14845	24 effective.
14846	14846	25 (b-5) As used in this subsection (b-5):
14847	14847	26 "Qualifying direct current applicant" means an entity that
14848	14848
14849	14849
14850	14850
14851	14851
14852	14852
14853	14853	HB3779 - 413 - LRB104 11172 AAS 21254 b
14854	14854
14855	14855
14856	14856	HB3779- 414 -LRB104 11172 AAS 21254 b HB3779 - 414 - LRB104 11172 AAS 21254 b
14857	14857	HB3779 - 414 - LRB104 11172 AAS 21254 b
14858	14858	1 seeks to provide direct current bulk transmission service for
14859	14859	2 the purpose of transporting electric energy in interstate
14860	14860	3 commerce.
14861	14861	4 "Qualifying direct current project" means a high voltage
14862	14862	5 direct current electric service line that crosses at least one
14863	14863	6 Illinois border, the Illinois portion of which is physically
14864	14864	7 located within the region of the Midcontinent Independent
14865	14865	8 System Operator, Inc., or its successor organization, and runs
14866	14866	9 through the counties of Pike, Scott, Greene, Macoupin,
14867	14867	10 Montgomery, Christian, Shelby, Cumberland, and Clark, is
14868	14868	11 capable of transmitting electricity at voltages of 345
14869	14869	12 kilovolts or above, and may also include associated
14870	14870	13 interconnected alternating current interconnection facilities
14871	14871	14 in this State that are part of the proposed project and
14872	14872	15 reasonably necessary to connect the project with other
14873	14873	16 portions of the grid.
14874	14874	17 Notwithstanding any other provision of this Act, a
14875	14875	18 qualifying direct current applicant that does not own,
14876	14876	19 control, operate, or manage, within this State, any plant,
14877	14877	20 equipment, or property used or to be used for the transmission
14878	14878	21 of electricity at the time of its application or of the
14879	14879	22 Commission's order may file an application on or before
14880	14880	23 December 31, 2023 with the Commission pursuant to this Section
14881	14881	24 or Section 8-406.1 for, and the Commission may grant, a
14882	14882	25 certificate of public convenience and necessity to construct,
14883	14883	26 operate, and maintain a qualifying direct current project. The
14884	14884
14885	14885
14886	14886
14887	14887
14888	14888
14889	14889	HB3779 - 414 - LRB104 11172 AAS 21254 b
14890	14890
14891	14891
14892	14892	HB3779- 415 -LRB104 11172 AAS 21254 b HB3779 - 415 - LRB104 11172 AAS 21254 b
14893	14893	HB3779 - 415 - LRB104 11172 AAS 21254 b
14894	14894	1 qualifying direct current applicant may also include in the
14895	14895	2 application requests for authority under Section 8-503. The
14896	14896	3 Commission shall grant the application for a certificate of
14897	14897	4 public convenience and necessity and requests for authority
14898	14898	5 under Section 8-503 if it finds that the qualifying direct
14899	14899	6 current applicant and the proposed qualifying direct current
14900	14900	7 project satisfy the requirements of this subsection and
14901	14901	8 otherwise satisfy the criteria of this Section or Section
14902	14902	9 8-406.1 and the criteria of Section 8-503, as applicable to
14903	14903	10 the application and to the extent such criteria are not
14904	14904	11 superseded by the provisions of this subsection. The
14905	14905	12 Commission's order on the application for the certificate of
14906	14906	13 public convenience and necessity shall also include the
14907	14907	14 Commission's findings and determinations on the request or
14908	14908	15 requests for authority pursuant to Section 8-503. Prior to
14909	14909	16 filing its application under either this Section or Section
14910	14910	17 8-406.1, the qualifying direct current applicant shall conduct
14911	14911	18 3 public meetings in accordance with subsection (h) of this
14912	14912	19 Section. If the qualifying direct current applicant
14913	14913	20 demonstrates in its application that the proposed qualifying
14914	14914	21 direct current project is designed to deliver electricity to a
14915	14915	22 point or points on the electric transmission grid in either or
14916	14916	23 both the PJM Interconnection, LLC or the Midcontinent
14917	14917	24 Independent System Operator, Inc., or their respective
14918	14918	25 successor organizations, the proposed qualifying direct
14919	14919	26 current project shall be deemed to be, and the Commission
14920	14920
14921	14921
14922	14922
14923	14923
14924	14924
14925	14925	HB3779 - 415 - LRB104 11172 AAS 21254 b
14926	14926
14927	14927
14928	14928	HB3779- 416 -LRB104 11172 AAS 21254 b HB3779 - 416 - LRB104 11172 AAS 21254 b
14929	14929	HB3779 - 416 - LRB104 11172 AAS 21254 b
14930	14930	1 shall find it to be, for public use. If the qualifying direct
14931	14931	2 current applicant further demonstrates in its application that
14932	14932	3 the proposed transmission project has a capacity of 1,000
14933	14933	4 megawatts or larger and a voltage level of 345 kilovolts or
14934	14934	5 greater, the proposed transmission project shall be deemed to
14935	14935	6 satisfy, and the Commission shall find that it satisfies, the
14936	14936	7 criteria stated in item (1) of subsection (b) of this Section
14937	14937	8 or in paragraph (1) of subsection (f) of Section 8-406.1, as
14938	14938	9 applicable to the application, without the taking of
14939	14939	10 additional evidence on these criteria. Prior to the transfer
14940	14940	11 of functional control of any transmission assets to a regional
14941	14941	12 transmission organization, a qualifying direct current
14942	14942	13 applicant shall request Commission approval to join a regional
14943	14943	14 transmission organization in an application filed pursuant to
14944	14944	15 this subsection (b-5) or separately pursuant to Section 7-102
14945	14945	16 of this Act. The Commission may grant permission to a
14946	14946	17 qualifying direct current applicant to join a regional
14947	14947	18 transmission organization if it finds that the membership, and
14948	14948	19 associated transfer of functional control of transmission
14949	14949	20 assets, benefits Illinois customers in light of the attendant
14950	14950	21 costs and is otherwise in the public interest. Nothing in this
14951	14951	22 subsection (b-5) requires a qualifying direct current
14952	14952	23 applicant to join a regional transmission organization.
14953	14953	24 Nothing in this subsection (b-5) requires the owner or
14954	14954	25 operator of a high voltage direct current transmission line
14955	14955	26 that is not a qualifying direct current project to obtain a
14956	14956
14957	14957
14958	14958
14959	14959
14960	14960
14961	14961	HB3779 - 416 - LRB104 11172 AAS 21254 b
14962	14962
14963	14963
14964	14964	HB3779- 417 -LRB104 11172 AAS 21254 b HB3779 - 417 - LRB104 11172 AAS 21254 b
14965	14965	HB3779 - 417 - LRB104 11172 AAS 21254 b
14966	14966	1 certificate of public convenience and necessity to the extent
14967	14967	2 it is not otherwise required by this Section 8-406 or any other
14968	14968	3 provision of this Act.
14969	14969	4 (c) As used in this subsection (c):
14970	14970	5 "Decommissioning" has the meaning given to that term in
14971	14971	6 subsection (a) of Section 8-508.1.
14972	14972	7 "Nuclear power reactor" has the meaning given to that term
14973	14973	8 in Section 8 of the Nuclear Safety Law of 2004.
14974	14974	9 After the effective date of this amendatory Act of the
14975	14975	10 103rd General Assembly, no construction shall commence on any
14976	14976	11 new nuclear power reactor with a nameplate capacity of more
14977	14977	12 than 300 megawatts of electricity to be located within this
14978	14978	13 State, and no certificate of public convenience and necessity
14979	14979	14 or other authorization shall be issued therefor by the
14980	14980	15 Commission, until the Illinois Emergency Management Agency and
14981	14981	16 Office of Homeland Security, in consultation with the Illinois
14982	14982	17 Environmental Protection Agency and the Illinois Department of
14983	14983	18 Natural Resources, finds that the United States Government,
14984	14984	19 through its authorized agency, has identified and approved a
14985	14985	20 demonstrable technology or means for the disposal of high
14986	14986	21 level nuclear waste, or until such construction has been
14987	14987	22 specifically approved by a statute enacted by the General
14988	14988	23 Assembly. Beginning January 1, 2026, construction may commence
14989	14989	24 on a new nuclear power reactor with a nameplate capacity of 300
14990	14990	25 megawatts of electricity or less within this State if the
14991	14991	26 entity constructing the new nuclear power reactor has obtained
14992	14992
14993	14993
14994	14994
14995	14995
14996	14996
14997	14997	HB3779 - 417 - LRB104 11172 AAS 21254 b
14998	14998
14999	14999
15000	15000	HB3779- 418 -LRB104 11172 AAS 21254 b HB3779 - 418 - LRB104 11172 AAS 21254 b
15001	15001	HB3779 - 418 - LRB104 11172 AAS 21254 b
15002	15002	1 all permits, licenses, permissions, or approvals governing the
15003	15003	2 construction, operation, and funding of decommissioning of
15004	15004	3 such nuclear power reactors required by: (1) this Act; (2) any
15005	15005	4 rules adopted by the Illinois Emergency Management Agency and
15006	15006	5 Office of Homeland Security under the authority of this Act;
15007	15007	6 (3) any applicable federal statutes, including, but not
15008	15008	7 limited to, the Atomic Energy Act of 1954, the Energy
15009	15009	8 Reorganization Act of 1974, the Low-Level Radioactive Waste
15010	15010	9 Policy Amendments Act of 1985, and the Energy Policy Act of
15011	15011	10 1992; (4) any regulations promulgated or enforced by the U.S.
15012	15012	11 Nuclear Regulatory Commission, including, but not limited to,
15013	15013	12 those codified at Title X, Parts 20, 30, 40, 50, 70, and 72 of
15014	15014	13 the Code of Federal Regulations, as from time to time amended;
15015	15015	14 and (5) any other federal or State statute, rule, or
15016	15016	15 regulation governing the permitting, licensing, operation, or
15017	15017	16 decommissioning of such nuclear power reactors. None of the
15018	15018	17 rules developed by the Illinois Emergency Management Agency
15019	15019	18 and Office of Homeland Security or any other State agency,
15020	15020	19 board, or commission pursuant to this Act shall be construed
15021	15021	20 to supersede the authority of the U.S. Nuclear Regulatory
15022	15022	21 Commission. The changes made by this amendatory Act of the
15023	15023	22 103rd General Assembly shall not apply to the uprate, renewal,
15024	15024	23 or subsequent renewal of any license for an existing nuclear
15025	15025	24 power reactor that began operation prior to the effective date
15026	15026	25 of this amendatory Act of the 103rd General Assembly.
15027	15027	26 None of the changes made in this amendatory Act of the
15028	15028
15029	15029
15030	15030
15031	15031
15032	15032
15033	15033	HB3779 - 418 - LRB104 11172 AAS 21254 b
15034	15034
15035	15035
15036	15036	HB3779- 419 -LRB104 11172 AAS 21254 b HB3779 - 419 - LRB104 11172 AAS 21254 b
15037	15037	HB3779 - 419 - LRB104 11172 AAS 21254 b
15038	15038	1 103rd General Assembly are intended to authorize the
15039	15039	2 construction of nuclear power plants powered by nuclear power
15040	15040	3 reactors that are not either: (1) small modular nuclear
15041	15041	4 reactors; or (2) nuclear power reactors licensed by the U.S.
15042	15042	5 Nuclear Regulatory Commission to operate in this State prior
15043	15043	6 to the effective date of this amendatory Act of the 103rd
15044	15044	7 General Assembly.
15045	15045	8 (d) In making its determination under subsection (b) of
15046	15046	9 this Section, the Commission shall attach primary weight to
15047	15047	10 the cost or cost savings to the customers of the utility. The
15048	15048	11 Commission may consider any or all factors which will or may
15049	15049	12 affect such cost or cost savings, including the public
15050	15050	13 utility's engineering judgment regarding the materials used
15051	15051	14 for construction.
15052	15052	15 (e) The Commission may issue a temporary certificate which
15053	15053	16 shall remain in force not to exceed one year in cases of
15054	15054	17 emergency, to assure maintenance of adequate service or to
15055	15055	18 serve particular customers, without notice or hearing, pending
15056	15056	19 the determination of an application for a certificate, and may
15057	15057	20 by regulation exempt from the requirements of this Section
15058	15058	21 temporary acts or operations for which the issuance of a
15059	15059	22 certificate will not be required in the public interest.
15060	15060	23 A public utility shall not be required to obtain but may
15061	15061	24 apply for and obtain a certificate of public convenience and
15062	15062	25 necessity pursuant to this Section with respect to any matter
15063	15063	26 as to which it has received the authorization or order of the
15064	15064
15065	15065
15066	15066
15067	15067
15068	15068
15069	15069	HB3779 - 419 - LRB104 11172 AAS 21254 b
15070	15070
15071	15071
15072	15072	HB3779- 420 -LRB104 11172 AAS 21254 b HB3779 - 420 - LRB104 11172 AAS 21254 b
15073	15073	HB3779 - 420 - LRB104 11172 AAS 21254 b
15074	15074	1 Commission under the Electric Supplier Act, and any such
15075	15075	2 authorization or order granted a public utility by the
15076	15076	3 Commission under that Act shall as between public utilities be
15077	15077	4 deemed to be, and shall have except as provided in that Act the
15078	15078	5 same force and effect as, a certificate of public convenience
15079	15079	6 and necessity issued pursuant to this Section.
15080	15080	7 No electric cooperative shall be made or shall become a
15081	15081	8 party to or shall be entitled to be heard or to otherwise
15082	15082	9 appear or participate in any proceeding initiated under this
15083	15083	10 Section for authorization of power plant construction and as
15084	15084	11 to matters as to which a remedy is available under the Electric
15085	15085	12 Supplier Act.
15086	15086	13 (f) Such certificates may be altered or modified by the
15087	15087	14 Commission, upon its own motion or upon application by the
15088	15088	15 person or corporation affected. Unless exercised within a
15089	15089	16 period of 2 years from the grant thereof, authority conferred
15090	15090	17 by a certificate of convenience and necessity issued by the
15091	15091	18 Commission shall be null and void.
15092	15092	19 No certificate of public convenience and necessity shall
15093	15093	20 be construed as granting a monopoly or an exclusive privilege,
15094	15094	21 immunity or franchise.
15095	15095	22 (g) A public utility that undertakes any of the actions
15096	15096	23 described in items (1) through (3) of this subsection (g) or
15097	15097	24 that has obtained approval pursuant to Section 8-406.1 of this
15098	15098	25 Act shall not be required to comply with the requirements of
15099	15099	26 this Section to the extent such requirements otherwise would
15100	15100
15101	15101
15102	15102
15103	15103
15104	15104
15105	15105	HB3779 - 420 - LRB104 11172 AAS 21254 b
15106	15106
15107	15107
15108	15108	HB3779- 421 -LRB104 11172 AAS 21254 b HB3779 - 421 - LRB104 11172 AAS 21254 b
15109	15109	HB3779 - 421 - LRB104 11172 AAS 21254 b
15110	15110	1 apply. For purposes of this Section and Section 8-406.1 of
15111	15111	2 this Act, "high voltage electric service line" means an
15112	15112	3 electric line having a design voltage of 100,000 or more. For
15113	15113	4 purposes of this subsection (g), a public utility may do any of
15114	15114	5 the following:
15115	15115	6 (1) replace or upgrade any existing high voltage
15116	15116	7 electric service line and related facilities,
15117	15117	8 notwithstanding its length;
15118	15118	9 (2) relocate any existing high voltage electric
15119	15119	10 service line and related facilities, notwithstanding its
15120	15120	11 length, to accommodate construction or expansion of a
15121	15121	12 roadway or other transportation infrastructure; or
15122	15122	13 (3) construct a high voltage electric service line and
15123	15123	14 related facilities that is constructed solely to serve a
15124	15124	15 single customer's premises or to provide a generator
15125	15125	16 interconnection to the public utility's transmission
15126	15126	17 system and that will pass under or over the premises owned
15127	15127	18 by the customer or generator to be served or under or over
15128	15128	19 premises for which the customer or generator has secured
15129	15129	20 the necessary right of way.
15130	15130	21 (h) A public utility seeking to construct a high-voltage
15131	15131	22 electric service line and related facilities (Project) must
15132	15132	23 show that the utility has held a minimum of 2 pre-filing public
15133	15133	24 meetings to receive public comment concerning the Project in
15134	15134	25 each county where the Project is to be located, no earlier than
15135	15135	26 6 months prior to filing an application for a certificate of
15136	15136
15137	15137
15138	15138
15139	15139
15140	15140
15141	15141	HB3779 - 421 - LRB104 11172 AAS 21254 b
15142	15142
15143	15143
15144	15144	HB3779- 422 -LRB104 11172 AAS 21254 b HB3779 - 422 - LRB104 11172 AAS 21254 b
15145	15145	HB3779 - 422 - LRB104 11172 AAS 21254 b
15146	15146	1 public convenience and necessity from the Commission. Notice
15147	15147	2 of the public meeting shall be published in a newspaper of
15148	15148	3 general circulation within the affected county once a week for
15149	15149	4 3 consecutive weeks, beginning no earlier than one month prior
15150	15150	5 to the first public meeting. If the Project traverses 2
15151	15151	6 contiguous counties and where in one county the transmission
15152	15152	7 line mileage and number of landowners over whose property the
15153	15153	8 proposed route traverses is one-fifth or less of the
15154	15154	9 transmission line mileage and number of such landowners of the
15155	15155	10 other county, then the utility may combine the 2 pre-filing
15156	15156	11 meetings in the county with the greater transmission line
15157	15157	12 mileage and affected landowners. All other requirements
15158	15158	13 regarding pre-filing meetings shall apply in both counties.
15159	15159	14 Notice of the public meeting, including a description of the
15160	15160	15 Project, must be provided in writing to the clerk of each
15161	15161	16 county where the Project is to be located. A representative of
15162	15162	17 the Commission shall be invited to each pre-filing public
15163	15163	18 meeting.
15164	15164	19 (i) For applications filed after August 18, 2015 (the
15165	15165	20 effective date of Public Act 99-399), the Commission shall, by
15166	15166	21 certified mail, notify each owner of record of land, as
15167	15167	22 identified in the records of the relevant county tax assessor,
15168	15168	23 included in the right-of-way over which the utility seeks in
15169	15169	24 its application to construct a high-voltage electric line of
15170	15170	25 the time and place scheduled for the initial hearing on the
15171	15171	26 public utility's application. The utility shall reimburse the
15172	15172
15173	15173
15174	15174
15175	15175
15176	15176
15177	15177	HB3779 - 422 - LRB104 11172 AAS 21254 b
15178	15178
15179	15179
15180	15180	HB3779- 423 -LRB104 11172 AAS 21254 b HB3779 - 423 - LRB104 11172 AAS 21254 b
15181	15181	HB3779 - 423 - LRB104 11172 AAS 21254 b
15182	15182	1 Commission for the cost of the postage and supplies incurred
15183	15183	2 for mailing the notice.
15184	15184	3 (Source: P.A. 102-609, eff. 8-27-21; 102-662, eff. 9-15-21;
15185	15185	4 102-813, eff. 5-13-22; 102-931, eff. 5-27-22; 103-569, eff.
15186	15186	5 6-1-24.)
15187	15187	6 (220 ILCS 5/8-406.1)
15188	15188	7 Sec. 8-406.1. Certificate of public convenience and
15189	15189	8 necessity; expedited procedure.
15190	15190	9 (a) A public utility may apply for a certificate of public
15191	15191	10 convenience and necessity pursuant to this Section for the
15192	15192	11 construction of any new high voltage electric service line and
15193	15193	12 related facilities (Project). To facilitate the expedited
15194	15194	13 review process of an application filed pursuant to this
15195	15195	14 Section, an application shall include all of the following:
15196	15196	15 (1) Information in support of the application that
15197	15197	16 shall include the following:
15198	15198	17 (A) A detailed description of the Project,
15199	15199	18 including location maps and plot plans to scale
15200	15200	19 showing all major components.
15201	15201	20 (B) The following engineering data:
15202	15202	21 (i) a detailed Project description including:
15203	15203	22 (I) name and destination of the Project;
15204	15204	23 (II) design voltage rating (kV);
15205	15205	24 (III) operating voltage rating (kV); and
15206	15206	25 (IV) normal peak operating current rating;
15207	15207
15208	15208
15209	15209
15210	15210
15211	15211
15212	15212	HB3779 - 423 - LRB104 11172 AAS 21254 b
15213	15213
15214	15214
15215	15215	HB3779- 424 -LRB104 11172 AAS 21254 b HB3779 - 424 - LRB104 11172 AAS 21254 b
15216	15216	HB3779 - 424 - LRB104 11172 AAS 21254 b
15217	15217	1 (ii) a conductor, structures, and substations
15218	15218	2 description including:
15219	15219	3 (I) conductor size and type;
15220	15220	4 (II) type of structures;
15221	15221	5 (III) height of typical structures;
15222	15222	6 (IV) an explanation why these structures
15223	15223	7 were selected;
15224	15224	8 (V) dimensional drawings of the typical
15225	15225	9 structures to be used in the Project; and
15226	15226	10 (VI) a list of the names of all new (and
15227	15227	11 existing if applicable) substations or
15228	15228	12 switching stations that will be associated
15229	15229	13 with the proposed new high voltage electric
15230	15230	14 service line;
15231	15231	15 (iii) the location of the site and
15232	15232	16 right-of-way including:
15233	15233	17 (I) miles of right-of-way;
15234	15234	18 (II) miles of circuit;
15235	15235	19 (III) width of the right-of-way; and
15236	15236	20 (IV) a brief description of the area
15237	15237	21 traversed by the proposed high voltage
15238	15238	22 electric service line, including a description
15239	15239	23 of the general land uses in the area and the
15240	15240	24 type of terrain crossed by the proposed line;
15241	15241	25 (iv) assumptions, bases, formulae, and methods
15242	15242	26 used in the development and preparation of the
15243	15243
15244	15244
15245	15245
15246	15246
15247	15247
15248	15248	HB3779 - 424 - LRB104 11172 AAS 21254 b
15249	15249
15250	15250
15251	15251	HB3779- 425 -LRB104 11172 AAS 21254 b HB3779 - 425 - LRB104 11172 AAS 21254 b
15252	15252	HB3779 - 425 - LRB104 11172 AAS 21254 b
15253	15253	1 diagrams and accompanying data, and a technical
15254	15254	2 description providing the following information:
15255	15255	3 (I) number of circuits, with
15256	15256	4 identification as to whether the circuit is
15257	15257	5 overhead or underground;
15258	15258	6 (II) the operating voltage and frequency;
15259	15259	7 and
15260	15260	8 (III) conductor size and type and number
15261	15261	9 of conductors per phase;
15262	15262	10 (v) if the proposed interconnection is an
15263	15263	11 overhead line, the following additional
15264	15264	12 information also must be provided:
15265	15265	13 (I) the wind and ice loading design
15266	15266	14 parameters;
15267	15267	15 (II) a full description and drawing of a
15268	15268	16 typical supporting structure, including
15269	15269	17 strength specifications;
15270	15270	18 (III) structure spacing with typical
15271	15271	19 ruling and maximum spans;
15272	15272	20 (IV) conductor (phase) spacing; and
15273	15273	21 (V) the designed line-to-ground and
15274	15274	22 conductor-side clearances;
15275	15275	23 (vi) if an underground or underwater
15276	15276	24 interconnection is proposed, the following
15277	15277	25 additional information also must be provided:
15278	15278	26 (I) burial depth;
15279	15279
15280	15280
15281	15281
15282	15282
15283	15283
15284	15284	HB3779 - 425 - LRB104 11172 AAS 21254 b
15285	15285
15286	15286
15287	15287	HB3779- 426 -LRB104 11172 AAS 21254 b HB3779 - 426 - LRB104 11172 AAS 21254 b
15288	15288	HB3779 - 426 - LRB104 11172 AAS 21254 b
15289	15289	1 (II) type of cable and a description of
15290	15290	2 any required supporting equipment, such as
15291	15291	3 insulation medium pressurizing or forced
15292	15292	4 cooling;
15293	15293	5 (III) cathodic protection scheme; and
15294	15294	6 (IV) type of dielectric fluid and
15295	15295	7 safeguards used to limit potential spills in
15296	15296	8 waterways;
15297	15297	9 (vii) technical diagrams that provide
15298	15298	10 clarification of any item under this item (1)
15299	15299	11 should be included; and
15300	15300	12 (viii) applicant shall provide and identify a
15301	15301	13 primary right-of-way and one or more alternate
15302	15302	14 rights-of-way for the Project as part of the
15303	15303	15 filing. To the extent applicable, for each
15304	15304	16 right-of-way, an applicant shall provide the
15305	15305	17 information described in this subsection (a). Upon
15306	15306	18 a showing of good cause in its filing, an
15307	15307	19 applicant may be excused from providing and
15308	15308	20 identifying alternate rights-of-way.
15309	15309	21 (2) An application fee of $100,000, which shall be
15310	15310	22 paid into the Public Utility Fund at the time the Chief
15311	15311	23 Clerk of the Commission deems it complete and accepts the
15312	15312	24 filing.
15313	15313	25 (3) Information showing that the utility has held a
15314	15314	26 minimum of 3 pre-filing public meetings to receive public
15315	15315
15316	15316
15317	15317
15318	15318
15319	15319
15320	15320	HB3779 - 426 - LRB104 11172 AAS 21254 b
15321	15321
15322	15322
15323	15323	HB3779- 427 -LRB104 11172 AAS 21254 b HB3779 - 427 - LRB104 11172 AAS 21254 b
15324	15324	HB3779 - 427 - LRB104 11172 AAS 21254 b
15325	15325	1 comment concerning the Project in each county where the
15326	15326	2 Project is to be located, no earlier than 6 months prior to
15327	15327	3 the filing of the application. Notice of the public
15328	15328	4 meeting shall be published in a newspaper of general
15329	15329	5 circulation within the affected county once a week for 3
15330	15330	6 consecutive weeks, beginning no earlier than one month
15331	15331	7 prior to the first public meeting. If the Project
15332	15332	8 traverses 2 contiguous counties and where in one county
15333	15333	9 the transmission line mileage and number of landowners
15334	15334	10 over whose property the proposed route traverses is 1/5 or
15335	15335	11 less of the transmission line mileage and number of such
15336	15336	12 landowners of the other county, then the utility may
15337	15337	13 combine the 3 pre-filing meetings in the county with the
15338	15338	14 greater transmission line mileage and affected landowners.
15339	15339	15 All other requirements regarding pre-filing meetings shall
15340	15340	16 apply in both counties. Notice of the public meeting,
15341	15341	17 including a description of the Project, must be provided
15342	15342	18 in writing to the clerk of each county where the Project is
15343	15343	19 to be located. A representative of the Commission shall be
15344	15344	20 invited to each pre-filing public meeting.
15345	15345	21 For applications filed after the effective date of this
15346	15346	22 amendatory Act of the 99th General Assembly, the Commission
15347	15347	23 shall, by certified mail, notify each owner of record of the
15348	15348	24 land, as identified in the records of the relevant county tax
15349	15349	25 assessor, included in the primary or alternate rights-of-way
15350	15350	26 identified in the utility's application of the time and place
15351	15351
15352	15352
15353	15353
15354	15354
15355	15355
15356	15356	HB3779 - 427 - LRB104 11172 AAS 21254 b
15357	15357
15358	15358
15359	15359	HB3779- 428 -LRB104 11172 AAS 21254 b HB3779 - 428 - LRB104 11172 AAS 21254 b
15360	15360	HB3779 - 428 - LRB104 11172 AAS 21254 b
15361	15361	1 scheduled for the initial hearing upon the public utility's
15362	15362	2 application. The utility shall reimburse the Commission for
15363	15363	3 the cost of the postage and supplies incurred for mailing the
15364	15364	4 notice.
15365	15365	5 (b) At the first status hearing the administrative law
15366	15366	6 judge shall set a schedule for discovery that shall take into
15367	15367	7 consideration the expedited nature of the proceeding.
15368	15368	8 (c) Nothing in this Section prohibits a utility from
15369	15369	9 requesting, or the Commission from approving, protection of
15370	15370	10 confidential or proprietary information under applicable law.
15371	15371	11 The public utility may seek confidential protection of any of
15372	15372	12 the information provided pursuant to this Section, subject to
15373	15373	13 Commission approval.
15374	15374	14 (d) The public utility shall publish notice of its
15375	15375	15 application in the official State newspaper within 10 days
15376	15376	16 following the date of the application's filing.
15377	15377	17 (e) The public utility shall establish a dedicated website
15378	15378	18 for the Project 3 weeks prior to the first public meeting and
15379	15379	19 maintain the website until construction of the Project is
15380	15380	20 complete. The website address shall be included in all public
15381	15381	21 notices.
15382	15382	22 (f) The Commission shall, after notice and hearing, grant
15383	15383	23 a certificate of public convenience and necessity filed in
15384	15384	24 accordance with the requirements of this Section if, based
15385	15385	25 upon the application filed with the Commission and the
15386	15386	26 evidentiary record, it finds the Project will promote the
15387	15387
15388	15388
15389	15389
15390	15390
15391	15391
15392	15392	HB3779 - 428 - LRB104 11172 AAS 21254 b
15393	15393
15394	15394
15395	15395	HB3779- 429 -LRB104 11172 AAS 21254 b HB3779 - 429 - LRB104 11172 AAS 21254 b
15396	15396	HB3779 - 429 - LRB104 11172 AAS 21254 b
15397	15397	1 public convenience and necessity and that all of the following
15398	15398	2 criteria are satisfied:
15399	15399	3 (1) That the Project is necessary to provide adequate,
15400	15400	4 reliable, and efficient service to the public utility's
15401	15401	5 customers and is the least-cost means of satisfying the
15402	15402	6 service needs of the public utility's customers or that
15403	15403	7 the Project will promote the development of an effectively
15404	15404	8 competitive electricity market that operates efficiently,
15405	15405	9 is equitable to all customers, and is the least cost means
15406	15406	10 of satisfying those objectives.
15407	15407	11 (2) That the public utility is capable of efficiently
15408	15408	12 managing and supervising the construction process and has
15409	15409	13 taken sufficient action to ensure adequate and efficient
15410	15410	14 construction and supervision of the construction.
15411	15411	15 (3) That the public utility is capable of financing
15412	15412	16 the proposed construction without significant adverse
15413	15413	17 financial consequences for the utility or its customers.
15414	15414	18 (4) That the public utility plans to implement grid
15415	15415	19 enhancing technologies maximizing the value of the
15416	15416	20 project, such as but not limited to advanced power flow
15417	15417	21 control, topology optimization, and dynamic line rating,
15418	15418	22 unless the public utility demonstrates grid enhancing
15419	15419	23 technologies are not cost effective.
15420	15420	24 (g) The Commission shall issue its decision with findings
15421	15421	25 of fact and conclusions of law granting or denying the
15422	15422	26 application no later than 150 days after the application is
15423	15423
15424	15424
15425	15425
15426	15426
15427	15427
15428	15428	HB3779 - 429 - LRB104 11172 AAS 21254 b
15429	15429
15430	15430
15431	15431	HB3779- 430 -LRB104 11172 AAS 21254 b HB3779 - 430 - LRB104 11172 AAS 21254 b
15432	15432	HB3779 - 430 - LRB104 11172 AAS 21254 b
15433	15433	1 filed. The Commission may extend the 150-day deadline upon
15434	15434	2 notice by an additional 75 days if, on or before the 30th day
15435	15435	3 after the filing of the application, the Commission finds that
15436	15436	4 good cause exists to extend the 150-day period.
15437	15437	5 (h) In the event the Commission grants a public utility's
15438	15438	6 application for a certificate pursuant to this Section, the
15439	15439	7 public utility shall pay a one-time construction fee to each
15440	15440	8 county in which the Project is constructed within 30 days
15441	15441	9 after the completion of construction. The construction fee
15442	15442	10 shall be $20,000 per mile of high voltage electric service
15443	15443	11 line constructed in that county, or a proportionate fraction
15444	15444	12 of that fee. The fee shall be in lieu of any permitting fees
15445	15445	13 that otherwise would be imposed by a county. Counties
15446	15446	14 receiving a payment under this subsection (h) may distribute
15447	15447	15 all or portions of the fee to local taxing districts in that
15448	15448	16 county.
15449	15449	17 (i) Notwithstanding any other provisions of this Act, a
15450	15450	18 decision granting a certificate under this Section shall
15451	15451	19 include an order pursuant to Section 8-503 of this Act
15452	15452	20 authorizing or directing the construction of the high voltage
15453	15453	21 electric service line and related facilities as approved by
15454	15454	22 the Commission, in the manner and within the time specified in
15455	15455	23 said order.
15456	15456	24 (Source: P.A. 102-931, eff. 5-27-22.)
15457	15457	25 (220 ILCS 5/8-512)
15458	15458
15459	15459
15460	15460
15461	15461
15462	15462
15463	15463	HB3779 - 430 - LRB104 11172 AAS 21254 b
15464	15464
15465	15465
15466	15466	HB3779- 431 -LRB104 11172 AAS 21254 b HB3779 - 431 - LRB104 11172 AAS 21254 b
15467	15467	HB3779 - 431 - LRB104 11172 AAS 21254 b
15468	15468	1 Sec. 8-512. Renewable energy access plan.
15469	15469	2 (a) It is the policy of this State to promote
15470	15470	3 cost-effective transmission system development that ensures
15471	15471	4 reliability of the electric transmission system, lowers carbon
15472	15472	5 emissions, minimizes long-term costs for consumers, and
15473	15473	6 supports the electric policy goals of this State. The General
15474	15474	7 Assembly finds that:
15475	15475	8 (1) Transmission planning, primarily for reliability
15476	15476	9 purposes, but also for economic and public policy reasons
15477	15477	10 is conducted by regional transmission organizations in
15478	15478	11 which transmission-owning Illinois utilities and other
15479	15479	12 stakeholders are members.
15480	15480	13 (2) Order No. 1000 of the Federal Energy Regulatory
15481	15481	14 Commission requires regional transmission organizations to
15482	15482	15 plan for transmission system needs in light of State
15483	15483	16 public policies and to accept input from states during the
15484	15484	17 transmission system planning processes.
15485	15485	18 (3) The State of Illinois does not currently have a
15486	15486	19 comprehensive power and environmental policy planning
15487	15487	20 process to identify transmission infrastructure needs that
15488	15488	21 can serve as a vital input into the regional and
15489	15489	22 interregional transmission organization planning
15490	15490	23 processes conducted under Order No. 1000 and other laws
15491	15491	24 and regulations.
15492	15492	25 (4) This State is an electricity generation and power
15493	15493	26 transmission hub, and can leverage that position to invest
15494	15494
15495	15495
15496	15496
15497	15497
15498	15498
15499	15499	HB3779 - 431 - LRB104 11172 AAS 21254 b
15500	15500
15501	15501
15502	15502	HB3779- 432 -LRB104 11172 AAS 21254 b HB3779 - 432 - LRB104 11172 AAS 21254 b
15503	15503	HB3779 - 432 - LRB104 11172 AAS 21254 b
15504	15504	1 in infrastructure that enables new and existing Illinois
15505	15505	2 generators to meet the public policy goals of the State of
15506	15506	3 Illinois and of interconnected states while
15507	15507	4 cost-effectively supporting tens of thousands of jobs in
15508	15508	5 the renewable energy sector in this State.
15509	15509	6 (5) The nation has a need to readily access this
15510	15510	7 State's low-cost, clean electric power, and this State
15511	15511	8 also desires access to clean energy resources in other
15512	15512	9 states to develop and support its low-carbon economy and
15513	15513	10 keep electricity prices low in Illinois and interconnected
15514	15514	11 States.
15515	15515	12 (6) Existing transmission infrastructure may constrain
15516	15516	13 the State's achievement of 100% renewable energy by 2050,
15517	15517	14 the accelerated adoption of electric vehicles in a just
15518	15518	15 and equitable way, and electrification of additional
15519	15519	16 sectors of the Illinois economy.
15520	15520	17 (7) Transmission system congestion within this State
15521	15521	18 and the regional transmission organizations serving this
15522	15522	19 State limits the ability of this State's existing and new
15523	15523	20 electric generation facilities that do not emit carbon
15524	15524	21 dioxide, including renewable energy resources and zero
15525	15525	22 emission facilities, to serve the public policy goals of
15526	15526	23 this State and other states, which constrains investment
15527	15527	24 in this State.
15528	15528	25 (8) Investment in infrastructure to support existing
15529	15529	26 and new electric generation facilities that do not emit
15530	15530
15531	15531
15532	15532
15533	15533
15534	15534
15535	15535	HB3779 - 432 - LRB104 11172 AAS 21254 b
15536	15536
15537	15537
15538	15538	HB3779- 433 -LRB104 11172 AAS 21254 b HB3779 - 433 - LRB104 11172 AAS 21254 b
15539	15539	HB3779 - 433 - LRB104 11172 AAS 21254 b
15540	15540	1 carbon dioxide, including renewable energy resources and
15541	15541	2 zero emission facilities, stimulates significant economic
15542	15542	3 development and job growth in this State, as well as
15543	15543	4 creates environmental and public health benefits in this
15544	15544	5 State.
15545	15545	6 (9) Creating a forward-looking plan for this State's
15546	15546	7 electric transmission infrastructure, as opposed to
15547	15547	8 relying on case-by-case development and repeated marginal
15548	15548	9 upgrades, will achieve a lower-cost system for Illinois'
15549	15549	10 electricity customers. A forward-looking plan can also
15550	15550	11 help integrate and achieve a comprehensive set of
15551	15551	12 objectives and multiple state, regional, and national
15552	15552	13 policy goals.
15553	15553	14 (10) Alternatives to overhead electric transmission
15554	15554	15 lines can achieve cost-effective resolution of system
15555	15555	16 impacts and warrant investigation of the circumstances
15556	15556	17 under which those alternatives should be considered and
15557	15557	18 approved. The alternatives are likely to be beneficial as
15558	15558	19 investment in electric transmission infrastructure moves
15559	15559	20 forward.
15560	15560	21 (11) Because transmission planning is conducted
15561	15561	22 primarily by the regional transmission organizations, the
15562	15562	23 Commission should be advocating for the State's interests
15563	15563	24 at the regional transmission organizations to ensure that
15564	15564	25 such planning facilitates the State's policies and goals,
15565	15565	26 including overall consumer savings, power system
15566	15566
15567	15567
15568	15568
15569	15569
15570	15570
15571	15571	HB3779 - 433 - LRB104 11172 AAS 21254 b
15572	15572
15573	15573
15574	15574	HB3779- 434 -LRB104 11172 AAS 21254 b HB3779 - 434 - LRB104 11172 AAS 21254 b
15575	15575	HB3779 - 434 - LRB104 11172 AAS 21254 b
15576	15576	1 reliability, economic development, environmental
15577	15577	2 improvement, and carbon reduction.
15578	15578	3 (b) Consistent with the findings identified in subsection
15579	15579	4 (a), the Commission shall open an investigation to develop and
15580	15580	5 adopt a renewable energy access plan no later than December
15581	15581	6 31, 2022. To assist and support the Commission in the
15582	15582	7 development of the plan, the Commission shall retain the
15583	15583	8 services of technical and policy experts with relevant fields
15584	15584	9 of expertise, solicit technical and policy analysis from the
15585	15585	10 public, and provide for a 120-day open public comment period
15586	15586	11 after publication of a draft report, which shall be published
15587	15587	12 no later than 90 days after the comment period ends. The plan
15588	15588	13 shall, at a minimum, do the following:
15589	15589	14 (1) designate renewable energy access plan zones
15590	15590	15 throughout this State in areas in which renewable energy
15591	15591	16 resources and suitable land areas are sufficient for
15592	15592	17 developing generating capacity from renewable energy
15593	15593	18 technologies;
15594	15594	19 (2) develop a plan to achieve transmission capacity
15595	15595	20 necessary to deliver the electric output from renewable
15596	15596	21 energy technologies in the renewable energy access plan
15597	15597	22 zones to customers in Illinois and other states in a
15598	15598	23 manner that is most beneficial and cost-effective to
15599	15599	24 customers;
15600	15600	25 (3) use this State's position as an electricity
15601	15601	26 generation and power transmission hub to create new
15602	15602
15603	15603
15604	15604
15605	15605
15606	15606
15607	15607	HB3779 - 434 - LRB104 11172 AAS 21254 b
15608	15608
15609	15609
15610	15610	HB3779- 435 -LRB104 11172 AAS 21254 b HB3779 - 435 - LRB104 11172 AAS 21254 b
15611	15611	HB3779 - 435 - LRB104 11172 AAS 21254 b
15612	15612	1 investment in this State's renewable energy resources;
15613	15613	2 (4) consider programs, policies, and electric
15614	15614	3 transmission projects that can be adopted within this
15615	15615	4 State that promote the cost-effective delivery of power
15616	15616	5 from renewable energy resources interconnected to the bulk
15617	15617	6 electric system to meet the renewable portfolio standard
15618	15618	7 targets under subsection (c) of Section 1-75 of the
15619	15619	8 Illinois Power Agency Act;
15620	15620	9 (5) consider proposals to improve regional
15621	15621	10 transmission organizations' regional and interregional
15622	15622	11 system planning processes, especially proposals that
15623	15623	12 reduce costs and emissions, create jobs, and increase
15624	15624	13 State and regional power system reliability to prevent
15625	15625	14 high-cost outages that can endanger lives, and analyze of
15626	15626	15 how those proposals would improve reliability and
15627	15627	16 cost-effective delivery of electricity in Illinois and the
15628	15628	17 region;
15629	15629	18 (6) make findings and policy recommendations based on
15630	15630	19 technical and policy analysis regarding locations of
15631	15631	20 renewable energy access plan zones and the transmission
15632	15632	21 system developments needed to cost-effectively achieve the
15633	15633	22 public policy goals identified herein;
15634	15634	23 (6.5) make findings and policy recommendations based
15635	15635	24 on analysis regarding the impact of converting non-powered
15636	15636	25 dams to hydropower dams relative to the alternative
15637	15637	26 renewable energy resources; and
15638	15638
15639	15639
15640	15640
15641	15641
15642	15642
15643	15643	HB3779 - 435 - LRB104 11172 AAS 21254 b
15644	15644
15645	15645
15646	15646	HB3779- 436 -LRB104 11172 AAS 21254 b HB3779 - 436 - LRB104 11172 AAS 21254 b
15647	15647	HB3779 - 436 - LRB104 11172 AAS 21254 b
15648	15648	1 (7) present the Commission's conclusions and proposed
15649	15649	2 recommendations based on its analysis and use the findings
15650	15650	3 and policy recommendations to determine actions that the
15651	15651	4 Commission should take.
15652	15652	5 (c) No later than December 31, 2025, and every other year
15653	15653	6 thereafter, the Commission shall open an investigation to
15654	15654	7 develop and adopt an updated renewable energy access plan
15655	15655	8 that, at a minimum, evaluates the implementation and
15656	15656	9 effectiveness of the renewable energy access plan, recommends
15657	15657	10 improvements to the renewable energy access plan, and provides
15658	15658	11 changes to transmission capacity necessary to deliver electric
15659	15659	12 output from the renewable energy access plan zones.
15660	15660	13 (d) Advanced Transmission Technologies Study.
15661	15661	14 (1) The General Assembly finds that advanced
15662	15662	15 transmission technologies have an important role to play
15663	15663	16 in meeting the State's achievement of 100% renewable
15664	15664	17 energy by 2050.
15665	15665	18 (2) "Advanced Transmission Technology" includes but
15666	15666	19 not limited to: (i) technology that dynamically adjusts
15667	15667	20 the rated capacity of transmission lines based on
15668	15668	21 real-time conditions; (ii) advanced power flow controls
15669	15669	22 used to actively control the flow of electricity across
15670	15670	23 transmission lines to optimize usage and/or relieve
15671	15671	24 congestion; (iii) software or hardware used to identify
15672	15672	25 optimal transmission grid configurations and/or enable
15673	15673	26 routing power flows around congestion points; (iv)
15674	15674
15675	15675
15676	15676
15677	15677
15678	15678
15679	15679	HB3779 - 436 - LRB104 11172 AAS 21254 b
15680	15680
15681	15681
15682	15682	HB3779- 437 -LRB104 11172 AAS 21254 b HB3779 - 437 - LRB104 11172 AAS 21254 b
15683	15683	HB3779 - 437 - LRB104 11172 AAS 21254 b
15684	15684	1 advanced transmission line conductors that have a direct
15685	15685	2 current electrical resistance at least 10 percent lower
15686	15686	3 than existing conductors of a similar diameter on the
15687	15687	4 system.
15688	15688	5 (3) No later than January 1, 2026, and once every two
15689	15689	6 years thereafter, each transmission-owning Illinois
15690	15690	7 utility shall prepare an analysis to identify
15691	15691	8 opportunities where Advanced Transmission Technology
15692	15692	9 deployments on an element of the utility's existing
15693	15693	10 transmission system could achieve any of the following
15694	15694	11 purposes: (A) enhance system resilience or reliability;
15695	15695	12 (B) reduce potential siting conflicts or land impacts from
15696	15696	13 the development of new transmission lines; (C) promote the
15697	15697	14 cost-effective delivery of power from renewable energy
15698	15698	15 resources interconnected to the bulk electric system to
15699	15699	16 meet the renewable portfolio standard targets under
15700	15700	17 subsection (c) of Section 1-75 of the Illinois Power
15701	15701	18 Agency Act; (D) enable the interconnection of renewable
15702	15702	19 energy resources to meet the renewable portfolio standard
15703	15703	20 targets under subsection (c) of Section 1-75 of the
15704	15704	21 Illinois Power Agency Act; or (E) reduce curtailment of
15705	15705	22 renewable and/or zero-carbon resources. The Advanced
15706	15706	23 Transmission Technology Deployment Study should at a
15707	15707	24 minimum evaluate the four types of Advanced Transmission
15708	15708	25 Technologies defined in this subsection (d) and shall
15709	15709	26 provide a timeline for deploying any Advanced Transmission
15710	15710
15711	15711
15712	15712
15713	15713
15714	15714
15715	15715	HB3779 - 437 - LRB104 11172 AAS 21254 b
15716	15716
15717	15717
15718	15718	HB3779- 438 -LRB104 11172 AAS 21254 b HB3779 - 438 - LRB104 11172 AAS 21254 b
15719	15719	HB3779 - 438 - LRB104 11172 AAS 21254 b
15720	15720	1 Technology found to achieve the purposes of this
15721	15721	2 subsection.
15722	15722	3 (4) Within 30 days of completing the Advanced
15723	15723	4 Transmission Technology Deployment Study, the
15724	15724	5 transmission-owning Illinois utilities shall submit the
15725	15725	6 study to the Commission. The Commission shall open a
15726	15726	7 Notice of Inquiry or other public, non-decisional
15727	15727	8 proceeding to provide opportunity for public comment on
15728	15728	9 the Advanced Transmission Technology Deployment Study. The
15729	15729	10 transmission-owning Illinois utilities shall submit the
15730	15730	11 final Advanced Transmission Technology Deployment Study to
15731	15731	12 the relevant regional transmission planning entities for
15732	15732	13 consideration in upcoming regional planning studies.
15733	15733	14 (e) Grid Capacity Optimization Plan.
15734	15734	15 (1) The General Assembly finds that achieving
15735	15735	16 Illinois' climate goals and preserving affordability
15736	15736	17 requires optimizing the use of the existing transmission
15737	15737	18 system. With generator retirements and anticipated
15738	15738	19 increases in large point load growth on the horizon,
15739	15739	20 Illinois must fully leverage the existing capacity of the
15740	15740	21 transmission system to address near-term system needs.
15741	15741	22 Furthermore, many existing resources do not fully utilize
15742	15742	23 the total grid capacity allocated to them, creating
15743	15743	24 opportunities for new resources to connect to the grid
15744	15744	25 without the need for new grid upgrades, and take advantage
15745	15745	26 of this unused capacity provided they do not exceed the
15746	15746
15747	15747
15748	15748
15749	15749
15750	15750
15751	15751	HB3779 - 438 - LRB104 11172 AAS 21254 b
15752	15752
15753	15753
15754	15754	HB3779- 439 -LRB104 11172 AAS 21254 b HB3779 - 439 - LRB104 11172 AAS 21254 b
15755	15755	HB3779 - 439 - LRB104 11172 AAS 21254 b
15756	15756	1 limits assigned to the existing resource.
15757	15757	2 (2) No later than January 1, 2026, the Commission
15758	15758	3 shall draft a Grid Capacity Optimization Plan. Upon
15759	15759	4 completion of the Grid Capacity Optimization Plan, the
15760	15760	5 Commission shall open a Notice of Inquiry or other public,
15761	15761	6 non-decisional proceeding to provide opportunity for
15762	15762	7 public comment. Within 90 days of the conclusion of the
15763	15763	8 public comment period, the Commission shall post the final
15764	15764	9 Grid Capacity Optimization Plan on its website. The Grid
15765	15765	10 Capacity Optimization Plan shall achieve the following:
15766	15766	11 (A) Identify existing or new state processes that
15767	15767	12 could make full use of the headroom that exists on the
15768	15768	13 Illinois system and any reforms necessary to utilize
15769	15769	14 the identified capacity, including but not limited to
15770	15770	15 mechanisms to incentivize investment of new supply at
15771	15771	16 locations that optimizes the existing transmission
15772	15772	17 system, and distribution system planning and expansion
15773	15773	18 that would enable greater access of distributed energy
15774	15774	19 resources to wholesale markets;
15775	15775	20 (B) Identify interconnection reforms at the
15776	15776	21 Midcontinent Independent System Operator, Inc., PJM
15777	15777	22 Interconnection, LLC, or their successor constructs to
15778	15778	23 access existing headroom and deploy renewable
15779	15779	24 resources and/or storage resources on the Illinois
15780	15780	25 transmission system; and
15781	15781	26 (C) Identify deficiencies in planning processes at
15782	15782
15783	15783
15784	15784
15785	15785
15786	15786
15787	15787	HB3779 - 439 - LRB104 11172 AAS 21254 b
15788	15788
15789	15789
15790	15790	HB3779- 440 -LRB104 11172 AAS 21254 b HB3779 - 440 - LRB104 11172 AAS 21254 b
15791	15791	HB3779 - 440 - LRB104 11172 AAS 21254 b
15792	15792	1 the Midcontinent Independent System Operator, Inc.,
15793	15793	2 PJM Interconnection, LLC, or their successor
15794	15794	3 constructs that may introduce delay or unnecessary
15795	15795	4 costs in responding to plant closures.
15796	15796	5 (f) Transmission Headroom Study.
15797	15797	6 (1) No later than January 1, 2026, and updated every
15798	15798	7 other year thereafter, the Commission shall conduct a
15799	15799	8 comprehensive Transmission Headroom Study that shall, at a
15800	15800	9 minimum, identify the points of interconnection with
15801	15801	10 unused, existing transmission headroom on the Illinois
15802	15802	11 system, including that available capacity behind existing,
15803	15803	12 underutilized points of interconnection. "Headroom"
15804	15804	13 includes but is not limited to: (i) underutilized
15805	15805	14 transmission capacity; (ii) utilization of Surplus
15806	15806	15 Interconnection Service as defined in FERC Order 845, and
15807	15807	16 subsequent decisions; (iii) transmission capacity that is
15808	15808	17 unavailable due to deficiencies in regional transmission
15809	15809	18 organization procedures; and (iv) transmission capacity
15810	15810	19 expected to become available due to reasonably anticipated
15811	15811	20 generator retirements. The Commission shall coordinate
15812	15812	21 with the Midcontinent Independent System Operator, Inc.
15813	15813	22 and PJM Interconnection, LLC or their successor constructs
15814	15814	23 to access any data necessary to complete the Transmission
15815	15815	24 Headroom Study, and upon request, additional data shall be
15816	15816	25 provided to the Commission by the relevant Illinois
15817	15817	26 transmission owners. Additionally, the Illinois Power
15818	15818
15819	15819
15820	15820
15821	15821
15822	15822
15823	15823	HB3779 - 440 - LRB104 11172 AAS 21254 b
15824	15824
15825	15825
15826	15826	HB3779- 441 -LRB104 11172 AAS 21254 b HB3779 - 441 - LRB104 11172 AAS 21254 b
15827	15827	HB3779 - 441 - LRB104 11172 AAS 21254 b
15828	15828	1 Agency's Office of Energy Modeling shall provide any
15829	15829	2 technical support the Commission requires to conduct the
15830	15830	3 Transmission Headroom Study, including but not limited to
15831	15831	4 performing the headroom analysis or recommending external
15832	15832	5 consultants or other external entities if necessary.
15833	15833	6 (2) Within 30 days of completing the Transmission
15834	15834	7 Headroom Study, the Commission shall open a Notice of
15835	15835	8 Inquiry or other public, non-decisional proceeding to
15836	15836	9 provide opportunity for public comment. The Commission
15837	15837	10 shall submit the final Transmission Headroom Study to the
15838	15838	11 Midcontinent Independent System Operator, Inc. and PJM
15839	15839	12 Interconnection, LLC or their successor constructs for
15840	15840	13 consideration in upcoming regional planning studies,
15841	15841	14 interconnection reform efforts, and resource adequacy
15842	15842	15 evaluations.
15843	15843	16 (A) As part of updating the Transmission Headroom
15844	15844	17 Study, the Commission shall evaluate the effectiveness
15845	15845	18 of enacted state processes and regional transmission
15846	15846	19 organization interconnection and planning processes in
15847	15847	20 unlocking the available headroom identified in the
15848	15848	21 most recent Transmission Headroom Study and
15849	15849	22 recommending any new or modified policies to better
15850	15850	23 utilize the identified headroom.
15851	15851	24 (B) As part of updating the Transmission Headroom
15852	15852	25 Study, the Commission shall evaluate how deficiencies
15853	15853	26 in the retirement or replacement planning procedures
15854	15854
15855	15855
15856	15856
15857	15857
15858	15858
15859	15859	HB3779 - 441 - LRB104 11172 AAS 21254 b
15860	15860
15861	15861
15862	15862	HB3779- 442 -LRB104 11172 AAS 21254 b HB3779 - 442 - LRB104 11172 AAS 21254 b
15863	15863	HB3779 - 442 - LRB104 11172 AAS 21254 b
15864	15864	1 at the Midcontinent Independent System Operator, Inc.
15865	15865	2 and PJM Interconnection, LLC, or their successor
15866	15866	3 constructs may have contributed to any extended
15867	15867	4 operations of electric generating units as described
15868	15868	5 in subsection (k-5)(1) of Section 9.15 of the
15869	15869	6 Environmental Protection Act, and quantify the
15870	15870	7 associated excess costs borne by Illinois consumers as
15871	15871	8 a result.
15872	15872	9 (g) The Commission shall advocate at relevant regional
15873	15873	10 transmission organizations and through their relevant state
15874	15874	11 engagement forums to recommend new regional transmission
15875	15875	12 organization policies, rules, or actions necessary to achieve
15876	15876	13 the interconnection planning and generator replacement reforms
15877	15877	14 identified in the Grid Capacity Optimization Plan described in
15878	15878	15 subsection (e) or as updated in the most recent Transmission
15879	15879	16 Headroom Study described in subsection (f). If necessary, the
15880	15880	17 Commission shall coordinate with other state entities,
15881	15881	18 including the Office of the Illinois Attorney General, on
15882	15882	19 appropriate legal action to remedy any aspect of a regional
15883	15883	20 transmission organization's practices that fails to meet the
15884	15884	21 needs of Illinois consumers and the requirements of Illinois
15885	15885	22 law.
15886	15886	23 (Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24.)
15887	15887	24 (220 ILCS 5/9-229)
15888	15888	25 Sec. 9-229. Consideration of attorney and expert
15889	15889
15890	15890
15891	15891
15892	15892
15893	15893
15894	15894	HB3779 - 442 - LRB104 11172 AAS 21254 b
15895	15895
15896	15896
15897	15897	HB3779- 443 -LRB104 11172 AAS 21254 b HB3779 - 443 - LRB104 11172 AAS 21254 b
15898	15898	HB3779 - 443 - LRB104 11172 AAS 21254 b
15899	15899	1 compensation as an expense and intervenor compensation fund.
15900	15900	2 (a) The Commission shall specifically assess the justness
15901	15901	3 and reasonableness of any amount expended by a public utility
15902	15902	4 to compensate attorneys or technical experts to prepare and
15903	15903	5 litigate a general rate case filing. This issue shall be
15904	15904	6 expressly addressed in the Commission's final order.
15905	15905	7 (b) The State of Illinois shall create a Consumer
15906	15906	8 Intervenor Compensation Fund subject to the following:
15907	15907	9 (1) Provision of compensation for Consumer Interest
15908	15908	10 Representatives that intervene in Illinois Commerce
15909	15909	11 Commission proceedings will increase public engagement,
15910	15910	12 encourage additional transparency, expand the information
15911	15911	13 available to the Commission, and improve decision-making.
15912	15912	14 (2) As used in this Section, "consumer Consumer
15913	15913	15 interest representative" means:
15914	15914	16 (A) a residential utility customer or group of
15915	15915	17 residential utility customers represented by a
15916	15916	18 not-for-profit group or organization registered with
15917	15917	19 the Illinois Attorney General under the Solicitation
15918	15918	20 for Charity Act;
15919	15919	21 (B) representatives of not-for-profit groups or
15920	15920	22 organizations whose membership is limited to
15921	15921	23 residential utility customers; or
15922	15922	24 (C) representatives of not-for-profit groups or
15923	15923	25 organizations whose membership includes Illinois
15924	15924	26 residents and that address the community, economic,
15925	15925
15926	15926
15927	15927
15928	15928
15929	15929
15930	15930	HB3779 - 443 - LRB104 11172 AAS 21254 b
15931	15931
15932	15932
15933	15933	HB3779- 444 -LRB104 11172 AAS 21254 b HB3779 - 444 - LRB104 11172 AAS 21254 b
15934	15934	HB3779 - 444 - LRB104 11172 AAS 21254 b
15935	15935	1 environmental, or social welfare of Illinois
15936	15936	2 residents, except government agencies or intervenors
15937	15937	3 specifically authorized by Illinois law to participate
15938	15938	4 in Commission proceedings on behalf of Illinois
15939	15939	5 consumers.
15940	15940	6 (3) A consumer interest representative is eligible to
15941	15941	7 receive compensation from the consumer intervenor
15942	15942	8 compensation fund if its participation included lay or
15943	15943	9 expert testimony or legal briefing and argument concerning
15944	15944	10 the expenses, investments, rate design, rate impact, or
15945	15945	11 other matters affecting the pricing, rates, costs or other
15946	15946	12 charges associated with utility service, the Commission
15947	15947	13 adopts a material recommendation related to a significant
15948	15948	14 issue in the docket, and participation caused a
15949	15949	15 significant financial cost hardship to the participant;
15950	15950	16 however, no consumer interest representative shall be
15951	15951	17 eligible to receive an award pursuant to this Section if
15952	15952	18 the consumer interest representative receives any
15953	15953	19 compensation, funding, or donations, directly or
15954	15954	20 indirectly, from parties that have a financial interest in
15955	15955	21 the outcome of the proceeding.
15956	15956	22 (4) Within 30 days after September 15, 2021 (the
15957	15957	23 effective date of Public Act 102-662), each utility that
15958	15958	24 files a request for an increase in rates under Article IX
15959	15959	25 or Article XVI shall deposit an amount equal to one half of
15960	15960	26 the rate case attorney and expert expense allowed by the
15961	15961
15962	15962
15963	15963
15964	15964
15965	15965
15966	15966	HB3779 - 444 - LRB104 11172 AAS 21254 b
15967	15967
15968	15968
15969	15969	HB3779- 445 -LRB104 11172 AAS 21254 b HB3779 - 445 - LRB104 11172 AAS 21254 b
15970	15970	HB3779 - 445 - LRB104 11172 AAS 21254 b
15971	15971	1 Commission, but not to exceed $500,000, into the fund
15972	15972	2 within 35 days of the date of the Commission's Final final
15973	15973	3 Order in the rate case or 20 days after the denial of
15974	15974	4 rehearing under Section 10-113 of this Act, whichever is
15975	15975	5 later. The Consumer Intervenor Compensation Fund shall be
15976	15976	6 used to provide payment to consumer interest
15977	15977	7 representatives as described in this Section.
15978	15978	8 (5) An electric public utility with 3,000,000 or more
15979	15979	9 retail customers shall contribute $450,000 to the Consumer
15980	15980	10 Intervenor Compensation Fund within 60 days after
15981	15981	11 September 15, 2021 (the effective date of Public Act
15982	15982	12 102-662). A combined electric and gas public utility
15983	15983	13 serving fewer than 3,000,000 but more than 500,000 retail
15984	15984	14 customers shall contribute $225,000 to the Consumer
15985	15985	15 Intervenor Compensation Fund within 60 days after
15986	15986	16 September 15, 2021 (the effective date of Public Act
15987	15987	17 102-662). A gas public utility with 1,500,000 or more
15988	15988	18 retail customers that is not a combined electric and gas
15989	15989	19 public utility shall contribute $225,000 to the Consumer
15990	15990	20 Intervenor Compensation Fund within 60 days after
15991	15991	21 September 15, 2021 (the effective date of Public Act
15992	15992	22 102-662). A gas public utility with fewer than 1,500,000
15993	15993	23 retail customers but more than 300,000 retail customers
15994	15994	24 that is not a combined electric and gas public utility
15995	15995	25 shall contribute $80,000 to the Consumer Intervenor
15996	15996	26 Compensation Fund within 60 days after September 15, 2021
15997	15997
15998	15998
15999	15999
16000	16000
16001	16001
16002	16002	HB3779 - 445 - LRB104 11172 AAS 21254 b
16003	16003
16004	16004
16005	16005	HB3779- 446 -LRB104 11172 AAS 21254 b HB3779 - 446 - LRB104 11172 AAS 21254 b
16006	16006	HB3779 - 446 - LRB104 11172 AAS 21254 b
16007	16007	1 (the effective date of Public Act 102-662). A gas public
16008	16008	2 utility with fewer than 300,000 retail customers that is
16009	16009	3 not a combined electric and gas public utility shall
16010	16010	4 contribute $20,000 to the Consumer Intervenor Compensation
16011	16011	5 Fund within 60 days after September 15, 2021 (the
16012	16012	6 effective date of Public Act 102-662). A combined electric
16013	16013	7 and gas public utility serving fewer than 500,000 retail
16014	16014	8 customers shall contribute $20,000 to the Consumer
16015	16015	9 Intervenor Compensation Fund within 60 days after
16016	16016	10 September 15, 2021 (the effective date of Public Act
16017	16017	11 102-662). A water or sewer public utility serving more
16018	16018	12 than 100,000 retail customers shall contribute $80,000,
16019	16019	13 and a water or sewer public utility serving fewer than
16020	16020	14 100,000 but more than 10,000 retail customers shall
16021	16021	15 contribute $20,000.
16022	16022	16 (6)(A) Prior to the entry of a Final Order in a
16023	16023	17 docketed case, the Commission Administrator shall provide
16024	16024	18 a payment to a consumer interest representative that
16025	16025	19 demonstrates through a verified application for funding
16026	16026	20 that the consumer interest representative's participation
16027	16027	21 or intervention without an award of fees or costs imposes
16028	16028	22 a significant financial hardship based on a schedule to be
16029	16029	23 developed by the Commission. The Administrator may require
16030	16030	24 verification of costs incurred, including statements of
16031	16031	25 hours spent, as a condition to paying the consumer
16032	16032	26 interest representative prior to the entry of a Final
16033	16033
16034	16034
16035	16035
16036	16036
16037	16037
16038	16038	HB3779 - 446 - LRB104 11172 AAS 21254 b
16039	16039
16040	16040
16041	16041	HB3779- 447 -LRB104 11172 AAS 21254 b HB3779 - 447 - LRB104 11172 AAS 21254 b
16042	16042	HB3779 - 447 - LRB104 11172 AAS 21254 b
16043	16043	1 Order in a docketed case.
16044	16044	2 (B) If the Commission adopts a material recommendation
16045	16045	3 related to a significant issue in the docket and
16046	16046	4 participation caused a financial cost hardship to the
16047	16047	5 participant, then the consumer interest representative
16048	16048	6 shall be allowed payment for some or all of the consumer
16049	16049	7 interest representative's reasonable attorney's or
16050	16050	8 advocate's fees, reasonable expert witness fees, and other
16051	16051	9 reasonable costs of preparation for and participation in a
16052	16052	10 hearing or proceeding. Expenses related to travel or meals
16053	16053	11 shall not be compensable.
16054	16054	12 (C) The consumer interest representative shall submit
16055	16055	13 an itemized request for compensation to the Consumer
16056	16056	14 Intervenor Compensation Fund, including the advocate's or
16057	16057	15 attorney's reasonable fee rate, the number of hours
16058	16058	16 expended, reasonable expert and expert witness fees, and
16059	16059	17 other reasonable costs for the preparation for and
16060	16060	18 participation in the hearing and briefing within 30 days
16061	16061	19 of the Commission's final order after denial or decision
16062	16062	20 on rehearing, if any.
16063	16063	21 (7) Administration of the Fund.
16064	16064	22 (A) The Consumer Intervenor Compensation Fund is
16065	16065	23 created as a special fund in the State treasury. All
16066	16066	24 disbursements from the Consumer Intervenor Compensation
16067	16067	25 Fund shall be made only upon warrants of the Comptroller
16068	16068	26 drawn upon the Treasurer as custodian of the Fund upon
16069	16069
16070	16070
16071	16071
16072	16072
16073	16073
16074	16074	HB3779 - 447 - LRB104 11172 AAS 21254 b
16075	16075
16076	16076
16077	16077	HB3779- 448 -LRB104 11172 AAS 21254 b HB3779 - 448 - LRB104 11172 AAS 21254 b
16078	16078	HB3779 - 448 - LRB104 11172 AAS 21254 b
16079	16079	1 vouchers signed by the Executive Director of the
16080	16080	2 Commission or by the person or persons designated by the
16081	16081	3 Director for that purpose. The Comptroller is authorized
16082	16082	4 to draw the warrant upon vouchers so signed. The Treasurer
16083	16083	5 shall accept all warrants so signed and shall be released
16084	16084	6 from liability for all payments made on those warrants.
16085	16085	7 The Consumer Intervenor Compensation Fund shall be
16086	16086	8 administered by an Administrator that is a person or
16087	16087	9 entity that is independent of the Commission. The
16088	16088	10 administrator will be responsible for the prudent
16089	16089	11 management of the Consumer Intervenor Compensation Fund
16090	16090	12 and for recommendations for the award of consumer
16091	16091	13 intervenor compensation from the Consumer Intervenor
16092	16092	14 Compensation Fund. The Commission shall issue a request
16093	16093	15 for qualifications for a third-party program administrator
16094	16094	16 to administer the Consumer Intervenor Compensation Fund.
16095	16095	17 The third-party administrator shall be chosen through a
16096	16096	18 competitive bid process based on selection criteria and
16097	16097	19 requirements developed by the Commission. The Illinois
16098	16098	20 Procurement Code does not apply to the hiring or payment
16099	16099	21 of the Administrator. All Administrator costs may be paid
16100	16100	22 for using monies from the Consumer Intervenor Compensation
16101	16101	23 Fund, but the Program Administrator shall strive to
16102	16102	24 minimize costs in the implementation of the program.
16103	16103	25 (B) The computation of compensation awarded from the
16104	16104	26 fund shall take into consideration the market rates paid
16105	16105
16106	16106
16107	16107
16108	16108
16109	16109
16110	16110	HB3779 - 448 - LRB104 11172 AAS 21254 b
16111	16111
16112	16112
16113	16113	HB3779- 449 -LRB104 11172 AAS 21254 b HB3779 - 449 - LRB104 11172 AAS 21254 b
16114	16114	HB3779 - 449 - LRB104 11172 AAS 21254 b
16115	16115	1 to persons of comparable training and experience who offer
16116	16116	2 similar services, but may not exceed the comparable market
16117	16117	3 rate for services paid by the public utility as part of its
16118	16118	4 rate case expense.
16119	16119	5 (C)(1) Recommendations on the award of compensation by
16120	16120	6 the administrator shall include consideration of whether
16121	16121	7 the participation raised in good faith Commission adopted
16122	16122	8 a material recommendation related to a significant issue
16123	16123	9 in the docket and whether participation caused a
16124	16124	10 significant financial cost hardship to the participant and
16125	16125	11 the payment of compensation is fair, just and reasonable.
16126	16126	12 (2) Recommendations on the award of compensation by
16127	16127	13 the administrator shall be submitted to the Commission for
16128	16128	14 approval. Unless the Commission initiates an investigation
16129	16129	15 within 45 days after the notice to the Commission, the
16130	16130	16 award of compensation shall be allowed 45 days after
16131	16131	17 notice to the Commission. Such notice shall be given by
16132	16132	18 filing with the Commission on the Commission's e-docket
16133	16133	19 system, and keeping open for public inspection the award
16134	16134	20 for compensation proposed by the Administrator. The
16135	16135	21 Commission shall have power, and it is hereby given
16136	16136	22 authority, either upon complaint or upon its own
16137	16137	23 initiative without complaint, at once, and if it so
16138	16138	24 orders, without answer or other formal pleadings, but upon
16139	16139	25 reasonable notice, to enter upon a hearing concerning the
16140	16140	26 propriety of the award.
16141	16141
16142	16142
16143	16143
16144	16144
16145	16145
16146	16146	HB3779 - 449 - LRB104 11172 AAS 21254 b
16147	16147
16148	16148
16149	16149	HB3779- 450 -LRB104 11172 AAS 21254 b HB3779 - 450 - LRB104 11172 AAS 21254 b
16150	16150	HB3779 - 450 - LRB104 11172 AAS 21254 b
16151	16151	1 (3) A consumer interest representative who performed
16152	16152	2 work or otherwise incurred expenses in an eligible
16153	16153	3 proceeding before the Illinois Commerce Commission prior
16154	16154	4 to the effective date of this amendatory Act of the 104th
16155	16155	5 General Assembly and after September 15, 2021 (the
16156	16156	6 effective date of Public Act 102-662) and who, due to a
16157	16157	7 denied application or otherwise, were not awarded
16158	16158	8 compensation for the entirety of these expenses from the
16159	16159	9 Consumer Intervenor Compensation Fund, may seek
16160	16160	10 compensation from the Consumer Intervenor Compensation
16161	16161	11 Fund pursuant to this Section. Nothing in this Section
16162	16162	12 shall prohibit retroactive awards to eligible
16163	16163	13 participants, for work performed or expenses incurred in
16164	16164	14 eligible proceedings prior to the effective date of this
16165	16165	15 amendatory Act of the 104th General Assembly and after
16166	16166	16 September 15, 2021 (the effective date of Public Act
16167	16167	17 102-662). Such applications shall be subject to the
16168	16168	18 revised eligibility standards enacted pursuant to this
16169	16169	19 amendatory Act of the 104th General Assembly. Such
16170	16170	20 applications may be submitted at any time within one
16171	16171	21 calendar year of the effective date of this amendatory Act
16172	16172	22 of the 104th General Assembly.
16173	16173	23 (c) The Commission may adopt rules to implement this
16174	16174	24 Section.
16175	16175	25 (Source: P.A. 102-662, eff. 9-15-21; 103-605, eff. 7-1-24.)
16176	16176
16177	16177
16178	16178
16179	16179
16180	16180
16181	16181	HB3779 - 450 - LRB104 11172 AAS 21254 b
16182	16182
16183	16183
16184	16184	HB3779- 451 -LRB104 11172 AAS 21254 b HB3779 - 451 - LRB104 11172 AAS 21254 b
16185	16185	HB3779 - 451 - LRB104 11172 AAS 21254 b
16186	16186	1 (220 ILCS 5/16-107.5)
16187	16187	2 Sec. 16-107.5. Net electricity metering.
16188	16188	3 (a) The General Assembly finds and declares that a program
16189	16189	4 to provide net electricity metering, as defined in this
16190	16190	5 Section, for eligible customers can encourage private
16191	16191	6 investment in renewable energy resources, stimulate economic
16192	16192	7 growth, enhance the continued diversification of Illinois'
16193	16193	8 energy resource mix, and protect the Illinois environment.
16194	16194	9 Further, to achieve the goals of this Act that robust options
16195	16195	10 for customer-site distributed generation continue to thrive in
16196	16196	11 Illinois, the General Assembly finds that a predictable
16197	16197	12 transition must be ensured for customers between full net
16198	16198	13 metering at the retail electricity rate to the distribution
16199	16199	14 generation rebate described in Section 16-107.6.
16200	16200	15 (b) As used in this Section, (i) "community renewable
16201	16201	16 generation project" shall have the meaning set forth in
16202	16202	17 Section 1-10 of the Illinois Power Agency Act; (ii) "eligible
16203	16203	18 customer" means a retail customer that owns, hosts, or
16204	16204	19 operates, including any third-party owned systems, a solar,
16205	16205	20 wind, or other eligible renewable electrical generating
16206	16206	21 facility that is located on the customer's premises or
16207	16207	22 customer's side of the billing meter and is intended primarily
16208	16208	23 to offset the customer's own current or future electrical
16209	16209	24 requirements; (iii) "electricity provider" means an electric
16210	16210	25 utility or alternative retail electric supplier; (iv)
16211	16211	26 "eligible renewable electrical generating facility" means a
16212	16212
16213	16213
16214	16214
16215	16215
16216	16216
16217	16217	HB3779 - 451 - LRB104 11172 AAS 21254 b
16218	16218
16219	16219
16220	16220	HB3779- 452 -LRB104 11172 AAS 21254 b HB3779 - 452 - LRB104 11172 AAS 21254 b
16221	16221	HB3779 - 452 - LRB104 11172 AAS 21254 b
16222	16222	1 generator, which may include the co-location of an energy
16223	16223	2 storage system, that is interconnected under rules adopted by
16224	16224	3 the Commission and is powered by solar electric energy, wind,
16225	16225	4 dedicated crops grown for electricity generation, agricultural
16226	16226	5 residues, untreated and unadulterated wood waste, livestock
16227	16227	6 manure, anaerobic digestion of livestock or food processing
16228	16228	7 waste, fuel cells or microturbines powered by renewable fuels,
16229	16229	8 or hydroelectric energy; (v) "net electricity metering" (or
16230	16230	9 "net metering") means the measurement, during the billing
16231	16231	10 period applicable to an eligible customer, of the net amount
16232	16232	11 of electricity supplied by an electricity provider to the
16233	16233	12 customer or provided to the electricity provider by the
16234	16234	13 customer or subscriber; (vi) "subscriber" shall have the
16235	16235	14 meaning as set forth in Section 1-10 of the Illinois Power
16236	16236	15 Agency Act; (vii) "subscription" shall have the meaning set
16237	16237	16 forth in Section 1-10 of the Illinois Power Agency Act; (viii)
16238	16238	17 "energy storage system" means commercially available
16239	16239	18 technology that is capable of absorbing energy and storing it
16240	16240	19 for a period of time for use at a later time, including, but
16241	16241	20 not limited to, electrochemical, thermal, and
16242	16242	21 electromechanical technologies, and may be interconnected
16243	16243	22 behind the customer's meter or interconnected behind its own
16244	16244	23 meter; and (ix) "future electrical requirements" means modeled
16245	16245	24 electrical requirements upon occupation of a new or vacant
16246	16246	25 property, and other reasonable expectations of future
16247	16247	26 electrical use, as well as, for occupied properties, a
16248	16248
16249	16249
16250	16250
16251	16251
16252	16252
16253	16253	HB3779 - 452 - LRB104 11172 AAS 21254 b
16254	16254
16255	16255
16256	16256	HB3779- 453 -LRB104 11172 AAS 21254 b HB3779 - 453 - LRB104 11172 AAS 21254 b
16257	16257	HB3779 - 453 - LRB104 11172 AAS 21254 b
16258	16258	1 reasonable approximation of the annual load of 2 electric
16259	16259	2 vehicles and, for non-electric heating customers, a reasonable
16260	16260	3 approximation of the incremental electric load associated with
16261	16261	4 fuel switching. The approximations shall be applied to the
16262	16262	5 appropriate net metering tariff and do not need to be unique to
16263	16263	6 each individual eligible customer. The utility shall submit
16264	16264	7 these approximations to the Commission for review,
16265	16265	8 modification, and approval; and (x) "electricity provider" and
16266	16266	9 "electric utility" includes municipalities and municipal power
16267	16267	10 agencies as defined in Section 11-119.3-1 of the Illinois
16268	16268	11 Municipal Code and electric cooperatives as defined in Section
16269	16269	12 3-119 of this Act.
16270	16270	13 (c) A net metering facility shall be equipped with
16271	16271	14 metering equipment that can measure the flow of electricity in
16272	16272	15 both directions at the same rate.
16273	16273	16 (1) For eligible customers whose electric service has
16274	16274	17 not been declared competitive pursuant to Section 16-113
16275	16275	18 of this Act as of July 1, 2011 and whose electric delivery
16276	16276	19 service is provided and measured on a kilowatt-hour basis
16277	16277	20 and electric supply service is not provided based on
16278	16278	21 hourly pricing, this shall typically be accomplished
16279	16279	22 through use of a single, bi-directional meter. If the
16280	16280	23 eligible customer's existing electric revenue meter does
16281	16281	24 not meet this requirement, the electricity provider shall
16282	16282	25 arrange for the local electric utility or a meter service
16283	16283	26 provider to install and maintain a new revenue meter at
16284	16284
16285	16285
16286	16286
16287	16287
16288	16288
16289	16289	HB3779 - 453 - LRB104 11172 AAS 21254 b
16290	16290
16291	16291
16292	16292	HB3779- 454 -LRB104 11172 AAS 21254 b HB3779 - 454 - LRB104 11172 AAS 21254 b
16293	16293	HB3779 - 454 - LRB104 11172 AAS 21254 b
16294	16294	1 the electricity provider's expense, which may be the smart
16295	16295	2 meter described by subsection (b) of Section 16-108.5 of
16296	16296	3 this Act.
16297	16297	4 (2) For eligible customers whose electric service has
16298	16298	5 not been declared competitive pursuant to Section 16-113
16299	16299	6 of this Act as of July 1, 2011 and whose electric delivery
16300	16300	7 service is provided and measured on a kilowatt demand
16301	16301	8 basis and electric supply service is not provided based on
16302	16302	9 hourly pricing, this shall typically be accomplished
16303	16303	10 through use of a dual channel meter capable of measuring
16304	16304	11 the flow of electricity both into and out of the
16305	16305	12 customer's facility at the same rate and ratio. If such
16306	16306	13 customer's existing electric revenue meter does not meet
16307	16307	14 this requirement, then the electricity provider shall
16308	16308	15 arrange for the local electric utility or a meter service
16309	16309	16 provider to install and maintain a new revenue meter at
16310	16310	17 the electricity provider's expense, which may be the smart
16311	16311	18 meter described by subsection (b) of Section 16-108.5 of
16312	16312	19 this Act.
16313	16313	20 (3) For all other eligible customers, until such time
16314	16314	21 as the local electric utility installs a smart meter, as
16315	16315	22 described by subsection (b) of Section 16-108.5 of this
16316	16316	23 Act, the electricity provider may arrange for the local
16317	16317	24 electric utility or a meter service provider to install
16318	16318	25 and maintain metering equipment capable of measuring the
16319	16319	26 flow of electricity both into and out of the customer's
16320	16320
16321	16321
16322	16322
16323	16323
16324	16324
16325	16325	HB3779 - 454 - LRB104 11172 AAS 21254 b
16326	16326
16327	16327
16328	16328	HB3779- 455 -LRB104 11172 AAS 21254 b HB3779 - 455 - LRB104 11172 AAS 21254 b
16329	16329	HB3779 - 455 - LRB104 11172 AAS 21254 b
16330	16330	1 facility at the same rate and ratio, typically through the
16331	16331	2 use of a dual channel meter. If the eligible customer's
16332	16332	3 existing electric revenue meter does not meet this
16333	16333	4 requirement, then the costs of installing such equipment
16334	16334	5 shall be paid for by the customer.
16335	16335	6 (d) An electricity provider shall measure and charge or
16336	16336	7 credit for the net electricity supplied to eligible customers
16337	16337	8 or provided by eligible customers whose electric service has
16338	16338	9 not been declared competitive pursuant to Section 16-113 of
16339	16339	10 this Act as of July 1, 2011 and whose electric delivery service
16340	16340	11 is provided and measured on a kilowatt-hour basis and electric
16341	16341	12 supply service is not provided based on hourly pricing in the
16342	16342	13 following manner:
16343	16343	14 (1) If the amount of electricity used by the customer
16344	16344	15 during the billing period exceeds the amount of
16345	16345	16 electricity produced by the customer, the electricity
16346	16346	17 provider shall charge the customer for the net electricity
16347	16347	18 supplied to and used by the customer as provided in
16348	16348	19 subsection (e-5) of this Section.
16349	16349	20 (2) If the amount of electricity produced by a
16350	16350	21 customer during the billing period exceeds the amount of
16351	16351	22 electricity used by the customer during that billing
16352	16352	23 period, the electricity provider supplying that customer
16353	16353	24 shall apply a 1:1 kilowatt-hour credit to a subsequent
16354	16354	25 bill for service to the customer for the net electricity
16355	16355	26 supplied to the electricity provider. The electricity
16356	16356
16357	16357
16358	16358
16359	16359
16360	16360
16361	16361	HB3779 - 455 - LRB104 11172 AAS 21254 b
16362	16362
16363	16363
16364	16364	HB3779- 456 -LRB104 11172 AAS 21254 b HB3779 - 456 - LRB104 11172 AAS 21254 b
16365	16365	HB3779 - 456 - LRB104 11172 AAS 21254 b
16366	16366	1 provider shall continue to carry over any excess
16367	16367	2 kilowatt-hour credits earned and apply those credits to
16368	16368	3 subsequent billing periods to offset any
16369	16369	4 customer-generator consumption in those billing periods
16370	16370	5 until all credits are used or until the end of the
16371	16371	6 annualized period.
16372	16372	7 (3) At the end of the year or annualized over the
16373	16373	8 period that service is supplied by means of net metering,
16374	16374	9 or in the event that the retail customer terminates
16375	16375	10 service with the electricity provider prior to the end of
16376	16376	11 the year or the annualized period, any remaining credits
16377	16377	12 in the customer's account shall expire.
16378	16378	13 (d-5) An electricity provider shall measure and charge or
16379	16379	14 credit for the net electricity supplied to eligible customers
16380	16380	15 or provided by eligible customers whose electric service has
16381	16381	16 not been declared competitive pursuant to Section 16-113 of
16382	16382	17 this Act as of July 1, 2011 and whose electric delivery service
16383	16383	18 is provided and measured on a kilowatt-hour basis and electric
16384	16384	19 supply service is provided based on hourly pricing or
16385	16385	20 time-of-use rates in the following manner:
16386	16386	21 (1) If the amount of electricity used by the customer
16387	16387	22 during any hourly period or time-of-use period exceeds the
16388	16388	23 amount of electricity produced by the customer, the
16389	16389	24 electricity provider shall charge the customer for the net
16390	16390	25 electricity supplied to and used by the customer according
16391	16391	26 to the terms of the contract or tariff to which the same
16392	16392
16393	16393
16394	16394
16395	16395
16396	16396
16397	16397	HB3779 - 456 - LRB104 11172 AAS 21254 b
16398	16398
16399	16399
16400	16400	HB3779- 457 -LRB104 11172 AAS 21254 b HB3779 - 457 - LRB104 11172 AAS 21254 b
16401	16401	HB3779 - 457 - LRB104 11172 AAS 21254 b
16402	16402	1 customer would be assigned to or be eligible for if the
16403	16403	2 customer was not a net metering customer.
16404	16404	3 (2) If the amount of electricity produced by a
16405	16405	4 customer during any hourly period or time-of-use period
16406	16406	5 exceeds the amount of electricity used by the customer
16407	16407	6 during that hourly period or time-of-use period, the
16408	16408	7 energy provider shall apply a credit for the net
16409	16409	8 kilowatt-hours produced in such period. The credit shall
16410	16410	9 consist of an energy credit and a delivery service credit.
16411	16411	10 The energy credit shall be valued at the same price per
16412	16412	11 kilowatt-hour as the electric service provider would
16413	16413	12 charge for kilowatt-hour energy sales during that same
16414	16414	13 hourly period or time-of-use period. The delivery credit
16415	16415	14 shall be equal to the net kilowatt-hours produced in such
16416	16416	15 hourly period or time-of-use period times a credit that
16417	16417	16 reflects all kilowatt-hour based charges in the customer's
16418	16418	17 electric service rate, excluding energy charges.
16419	16419	18 (e) An electricity provider shall measure and charge or
16420	16420	19 credit for the net electricity supplied to eligible customers
16421	16421	20 whose electric service has not been declared competitive
16422	16422	21 pursuant to Section 16-113 of this Act as of July 1, 2011 and
16423	16423	22 whose electric delivery service is provided and measured on a
16424	16424	23 kilowatt demand basis and electric supply service is not
16425	16425	24 provided based on hourly pricing in the following manner:
16426	16426	25 (1) If the amount of electricity used by the customer
16427	16427	26 during the billing period exceeds the amount of
16428	16428
16429	16429
16430	16430
16431	16431
16432	16432
16433	16433	HB3779 - 457 - LRB104 11172 AAS 21254 b
16434	16434
16435	16435
16436	16436	HB3779- 458 -LRB104 11172 AAS 21254 b HB3779 - 458 - LRB104 11172 AAS 21254 b
16437	16437	HB3779 - 458 - LRB104 11172 AAS 21254 b
16438	16438	1 electricity produced by the customer, then the electricity
16439	16439	2 provider shall charge the customer for the net electricity
16440	16440	3 supplied to and used by the customer as provided in
16441	16441	4 subsection (e-5) of this Section. The customer shall
16442	16442	5 remain responsible for all taxes, fees, and utility
16443	16443	6 delivery charges that would otherwise be applicable to the
16444	16444	7 net amount of electricity used by the customer.
16445	16445	8 (2) If the amount of electricity produced by a
16446	16446	9 customer during the billing period exceeds the amount of
16447	16447	10 electricity used by the customer during that billing
16448	16448	11 period, then the electricity provider supplying that
16449	16449	12 customer shall apply a 1:1 kilowatt-hour credit that
16450	16450	13 reflects the kilowatt-hour based charges in the customer's
16451	16451	14 electric service rate to a subsequent bill for service to
16452	16452	15 the customer for the net electricity supplied to the
16453	16453	16 electricity provider. The electricity provider shall
16454	16454	17 continue to carry over any excess kilowatt-hour credits
16455	16455	18 earned and apply those credits to subsequent billing
16456	16456	19 periods to offset any customer-generator consumption in
16457	16457	20 those billing periods until all credits are used or until
16458	16458	21 the end of the annualized period.
16459	16459	22 (3) At the end of the year or annualized over the
16460	16460	23 period that service is supplied by means of net metering,
16461	16461	24 or in the event that the retail customer terminates
16462	16462	25 service with the electricity provider prior to the end of
16463	16463	26 the year or the annualized period, any remaining credits
16464	16464
16465	16465
16466	16466
16467	16467
16468	16468
16469	16469	HB3779 - 458 - LRB104 11172 AAS 21254 b
16470	16470
16471	16471
16472	16472	HB3779- 459 -LRB104 11172 AAS 21254 b HB3779 - 459 - LRB104 11172 AAS 21254 b
16473	16473	HB3779 - 459 - LRB104 11172 AAS 21254 b
16474	16474	1 in the customer's account shall expire.
16475	16475	2 (e-5) An electricity provider shall provide electric
16476	16476	3 service to eligible customers who utilize net metering at
16477	16477	4 non-discriminatory rates that are identical, with respect to
16478	16478	5 rate structure, retail rate components, and any monthly
16479	16479	6 charges, to the rates that the customer would be charged if not
16480	16480	7 a net metering customer. An electricity provider shall not
16481	16481	8 charge net metering customers any fee or charge or require
16482	16482	9 additional equipment, insurance, or any other requirements not
16483	16483	10 specifically authorized by interconnection standards
16484	16484	11 authorized by the Commission, unless the fee, charge, or other
16485	16485	12 requirement would apply to other similarly situated customers
16486	16486	13 who are not net metering customers. The customer will remain
16487	16487	14 responsible for all taxes, fees, and utility delivery charges
16488	16488	15 that would otherwise be applicable to the net amount of
16489	16489	16 electricity used by the customer. Subsections (c) through (e)
16490	16490	17 of this Section shall not be construed to prevent an
16491	16491	18 arms-length agreement between an electricity provider and an
16492	16492	19 eligible customer that sets forth different prices, terms, and
16493	16493	20 conditions for the provision of net metering service,
16494	16494	21 including, but not limited to, the provision of the
16495	16495	22 appropriate metering equipment for non-residential customers.
16496	16496	23 (f) Notwithstanding the requirements of subsections (c)
16497	16497	24 through (e-5) of this Section, an electricity provider must
16498	16498	25 require dual-channel metering for customers operating eligible
16499	16499	26 renewable electrical generating facilities to whom the
16500	16500
16501	16501
16502	16502
16503	16503
16504	16504
16505	16505	HB3779 - 459 - LRB104 11172 AAS 21254 b
16506	16506
16507	16507
16508	16508	HB3779- 460 -LRB104 11172 AAS 21254 b HB3779 - 460 - LRB104 11172 AAS 21254 b
16509	16509	HB3779 - 460 - LRB104 11172 AAS 21254 b
16510	16510	1 provisions of neither subsection (d), (d-5), nor (e) of this
16511	16511	2 Section apply. In such cases, electricity charges and credits
16512	16512	3 shall be determined as follows:
16513	16513	4 (1) The electricity provider shall assess and the
16514	16514	5 customer remains responsible for all taxes, fees, and
16515	16515	6 utility delivery charges that would otherwise be
16516	16516	7 applicable to the gross amount of kilowatt-hours supplied
16517	16517	8 to the eligible customer by the electricity provider.
16518	16518	9 (2) Each month that service is supplied by means of
16519	16519	10 dual-channel metering, the electricity provider shall
16520	16520	11 compensate the eligible customer for any excess
16521	16521	12 kilowatt-hour credits at the electricity provider's
16522	16522	13 avoided cost of electricity supply over the monthly period
16523	16523	14 or as otherwise specified by the terms of a power-purchase
16524	16524	15 agreement negotiated between the customer and electricity
16525	16525	16 provider.
16526	16526	17 (3) For all eligible net metering customers taking
16527	16527	18 service from an electricity provider under contracts or
16528	16528	19 tariffs employing hourly or time-of-use rates, any monthly
16529	16529	20 consumption of electricity shall be calculated according
16530	16530	21 to the terms of the contract or tariff to which the same
16531	16531	22 customer would be assigned to or be eligible for if the
16532	16532	23 customer was not a net metering customer. When those same
16533	16533	24 customer-generators are net generators during any discrete
16534	16534	25 hourly or time-of-use period, the net kilowatt-hours
16535	16535	26 produced shall be valued at the same price per
16536	16536
16537	16537
16538	16538
16539	16539
16540	16540
16541	16541	HB3779 - 460 - LRB104 11172 AAS 21254 b
16542	16542
16543	16543
16544	16544	HB3779- 461 -LRB104 11172 AAS 21254 b HB3779 - 461 - LRB104 11172 AAS 21254 b
16545	16545	HB3779 - 461 - LRB104 11172 AAS 21254 b
16546	16546	1 kilowatt-hour as the electric service provider would
16547	16547	2 charge for retail kilowatt-hour sales during that same
16548	16548	3 time-of-use period.
16549	16549	4 (g) For purposes of federal and State laws providing
16550	16550	5 renewable energy credits or greenhouse gas credits, the
16551	16551	6 eligible customer shall be treated as owning and having title
16552	16552	7 to the renewable energy attributes, renewable energy credits,
16553	16553	8 and greenhouse gas emission credits related to any electricity
16554	16554	9 produced by the qualified generating unit. The electricity
16555	16555	10 provider may not condition participation in a net metering
16556	16556	11 program on the signing over of a customer's renewable energy
16557	16557	12 credits; provided, however, this subsection (g) shall not be
16558	16558	13 construed to prevent an arms-length agreement between an
16559	16559	14 electricity provider and an eligible customer that sets forth
16560	16560	15 the ownership or title of the credits.
16561	16561	16 (h) Within 120 days after the effective date of this
16562	16562	17 amendatory Act of the 95th General Assembly, the Commission
16563	16563	18 shall establish standards for net metering and, if the
16564	16564	19 Commission has not already acted on its own initiative,
16565	16565	20 standards for the interconnection of eligible renewable
16566	16566	21 generating equipment to the utility system. The
16567	16567	22 interconnection standards shall address any procedural
16568	16568	23 barriers, delays, and administrative costs associated with the
16569	16569	24 interconnection of customer-generation while ensuring the
16570	16570	25 safety and reliability of the units and the electric utility
16571	16571	26 system. The Commission shall consider the Institute of
16572	16572
16573	16573
16574	16574
16575	16575
16576	16576
16577	16577	HB3779 - 461 - LRB104 11172 AAS 21254 b
16578	16578
16579	16579
16580	16580	HB3779- 462 -LRB104 11172 AAS 21254 b HB3779 - 462 - LRB104 11172 AAS 21254 b
16581	16581	HB3779 - 462 - LRB104 11172 AAS 21254 b
16582	16582	1 Electrical and Electronics Engineers (IEEE) Standard 1547 and
16583	16583	2 the issues of (i) reasonable and fair fees and costs, (ii)
16584	16584	3 clear timelines for major milestones in the interconnection
16585	16585	4 process, (iii) nondiscriminatory terms of agreement, and (iv)
16586	16586	5 any best practices for interconnection of distributed
16587	16587	6 generation.
16588	16588	7 (h-5) Within 90 days after the effective date of this
16589	16589	8 amendatory Act of the 102nd General Assembly, the Commission
16590	16590	9 shall:
16591	16591	10 (1) establish an Interconnection Working Group. The
16592	16592	11 working group shall include representatives from electric
16593	16593	12 utilities, developers of renewable electric generating
16594	16594	13 facilities, other industries that regularly apply for
16595	16595	14 interconnection with the electric utilities,
16596	16596	15 representatives of distributed generation customers, the
16597	16597	16 Commission Staff, and such other stakeholders with a
16598	16598	17 substantial interest in the topics addressed by the
16599	16599	18 Interconnection Working Group. The Interconnection Working
16600	16600	19 Group shall address at least the following issues:
16601	16601	20 (A) cost and best available technology for
16602	16602	21 interconnection and metering, including the
16603	16603	22 standardization and publication of standard costs;
16604	16604	23 (B) transparency, accuracy and use of the
16605	16605	24 distribution interconnection queue and hosting
16606	16606	25 capacity maps;
16607	16607	26 (C) distribution system upgrade cost avoidance
16608	16608
16609	16609
16610	16610
16611	16611
16612	16612
16613	16613	HB3779 - 462 - LRB104 11172 AAS 21254 b
16614	16614
16615	16615
16616	16616	HB3779- 463 -LRB104 11172 AAS 21254 b HB3779 - 463 - LRB104 11172 AAS 21254 b
16617	16617	HB3779 - 463 - LRB104 11172 AAS 21254 b
16618	16618	1 through use of advanced inverter functions;
16619	16619	2 (D) predictability of the queue management process
16620	16620	3 and enforcement of timelines;
16621	16621	4 (E) benefits and challenges associated with group
16622	16622	5 studies and cost sharing;
16623	16623	6 (F) minimum requirements for application to the
16624	16624	7 interconnection process and throughout the
16625	16625	8 interconnection process to avoid queue clogging
16626	16626	9 behavior;
16627	16627	10 (G) process and customer service for
16628	16628	11 interconnecting customers adopting distributed energy
16629	16629	12 resources, including energy storage;
16630	16630	13 (H) options for metering distributed energy
16631	16631	14 resources, including energy storage;
16632	16632	15 (I) interconnection of new technologies, including
16633	16633	16 smart inverters and energy storage;
16634	16634	17 (J) collect, share, and examine data on Level 1
16635	16635	18 interconnection costs, including cost and type of
16636	16636	19 upgrades required for interconnection, and use this
16637	16637	20 data to inform the final standardized cost of Level 1
16638	16638	21 interconnection; and
16639	16639	22 (K) such other technical, policy, and tariff
16640	16640	23 issues related to and affecting interconnection
16641	16641	24 performance and customer service as determined by the
16642	16642	25 Interconnection Working Group.
16643	16643	26 The Commission may create subcommittees of the
16644	16644
16645	16645
16646	16646
16647	16647
16648	16648
16649	16649	HB3779 - 463 - LRB104 11172 AAS 21254 b
16650	16650
16651	16651
16652	16652	HB3779- 464 -LRB104 11172 AAS 21254 b HB3779 - 464 - LRB104 11172 AAS 21254 b
16653	16653	HB3779 - 464 - LRB104 11172 AAS 21254 b
16654	16654	1 Interconnection Working Group to focus on specific issues
16655	16655	2 of importance, as appropriate. The Interconnection Working
16656	16656	3 Group shall report to the Commission on recommended
16657	16657	4 improvements to interconnection rules and tariffs and
16658	16658	5 policies as determined by the Interconnection Working
16659	16659	6 Group at least every 6 months. Such reports shall include
16660	16660	7 consensus recommendations of the Interconnection Working
16661	16661	8 Group and, if applicable, additional recommendations for
16662	16662	9 which consensus was not reached. The Commission shall use
16663	16663	10 the report from the Interconnection Working Group to
16664	16664	11 determine whether processes should be commenced to
16665	16665	12 formally codify or implement the recommendations;
16666	16666	13 (2) create or contract for an Ombudsman to resolve
16667	16667	14 interconnection disputes through non-binding arbitration.
16668	16668	15 The Ombudsman may be paid in full or in part through fees
16669	16669	16 levied on the initiators of the dispute; and
16670	16670	17 (3) determine a single standardized cost for Level 1
16671	16671	18 interconnections, which shall not exceed $200.
16672	16672	19 (i) All electricity providers shall begin to offer net
16673	16673	20 metering no later than April 1, 2008.
16674	16674	21 (j) An electricity provider shall provide net metering to
16675	16675	22 eligible customers according to subsections (d), (d-5), and
16676	16676	23 (e). Eligible renewable electrical generating facilities for
16677	16677	24 which eligible customers registered for net metering before
16678	16678	25 January 1, 2025 shall continue to receive net metering
16679	16679	26 services according to subsections (d), (d-5), and (e) of this
16680	16680
16681	16681
16682	16682
16683	16683
16684	16684
16685	16685	HB3779 - 464 - LRB104 11172 AAS 21254 b
16686	16686
16687	16687
16688	16688	HB3779- 465 -LRB104 11172 AAS 21254 b HB3779 - 465 - LRB104 11172 AAS 21254 b
16689	16689	HB3779 - 465 - LRB104 11172 AAS 21254 b
16690	16690	1 Section for the lifetime of the system, regardless of whether
16691	16691	2 those retail customers change electricity providers or whether
16692	16692	3 the retail customer benefiting from the system changes. On and
16693	16693	4 after January 1, 2025, any eligible customer that applies for
16694	16694	5 net metering and previously would have qualified under
16695	16695	6 subsections (d), (d-5), or (e) shall only be eligible for net
16696	16696	7 metering as described in subsection (n).
16697	16697	8 (k) Each electricity provider shall maintain records and
16698	16698	9 report annually to the Commission the total number of net
16699	16699	10 metering customers served by the provider, as well as the
16700	16700	11 type, capacity, and energy sources of the generating systems
16701	16701	12 used by the net metering customers. Nothing in this Section
16702	16702	13 shall limit the ability of an electricity provider to request
16703	16703	14 the redaction of information deemed by the Commission to be
16704	16704	15 confidential business information.
16705	16705	16 (l)(1) Notwithstanding the definition of "eligible
16706	16706	17 customer" in item (ii) of subsection (b) of this Section, each
16707	16707	18 electricity provider shall allow net metering as set forth in
16708	16708	19 this subsection (l) and for the following projects, provided
16709	16709	20 that only electric utilities serving more than 200,000
16710	16710	21 customers as of January 1, 2021 shall provide net metering for
16711	16711	22 projects that are eligible for subparagraph (C) of this
16712	16712	23 paragraph (1) and have energized after the effective date of
16713	16713	24 this amendatory Act of the 102nd General Assembly:
16714	16714	25 (A) properties owned or leased by multiple customers
16715	16715	26 that contribute to the operation of an eligible renewable
16716	16716
16717	16717
16718	16718
16719	16719
16720	16720
16721	16721	HB3779 - 465 - LRB104 11172 AAS 21254 b
16722	16722
16723	16723
16724	16724	HB3779- 466 -LRB104 11172 AAS 21254 b HB3779 - 466 - LRB104 11172 AAS 21254 b
16725	16725	HB3779 - 466 - LRB104 11172 AAS 21254 b
16726	16726	1 electrical generating facility through an ownership or
16727	16727	2 leasehold interest of at least 200 watts in such facility,
16728	16728	3 such as a community-owned wind project, a community-owned
16729	16729	4 biomass project, a community-owned solar project, or a
16730	16730	5 community methane digester processing livestock waste from
16731	16731	6 multiple sources, provided that the facility is also
16732	16732	7 located within the utility's service territory;
16733	16733	8 (B) individual units, apartments, or properties
16734	16734	9 located in a single building that are owned or leased by
16735	16735	10 multiple customers and collectively served by a common
16736	16736	11 eligible renewable electrical generating facility, such as
16737	16737	12 an office or apartment building, a shopping center or
16738	16738	13 strip mall served by photovoltaic panels on the roof; and
16739	16739	14 (C) subscriptions to community renewable generation
16740	16740	15 projects, including community renewable generation
16741	16741	16 projects on the customer's side of the billing meter of a
16742	16742	17 host facility and partially used for the customer's own
16743	16743	18 load.
16744	16744	19 In addition, the nameplate capacity of the eligible
16745	16745	20 renewable electric generating facility that serves the demand
16746	16746	21 of the properties, units, or apartments identified in
16747	16747	22 paragraphs (1) and (2) of this subsection (l) shall not exceed
16748	16748	23 5,000 kilowatts in nameplate capacity in total. Any eligible
16749	16749	24 renewable electrical generating facility or community
16750	16750	25 renewable generation project that is powered by photovoltaic
16751	16751	26 electric energy and installed after the effective date of this
16752	16752
16753	16753
16754	16754
16755	16755
16756	16756
16757	16757	HB3779 - 466 - LRB104 11172 AAS 21254 b
16758	16758
16759	16759
16760	16760	HB3779- 467 -LRB104 11172 AAS 21254 b HB3779 - 467 - LRB104 11172 AAS 21254 b
16761	16761	HB3779 - 467 - LRB104 11172 AAS 21254 b
16762	16762	1 amendatory Act of the 99th General Assembly must be installed
16763	16763	2 by a qualified person in compliance with the requirements of
16764	16764	3 Section 16-128A of the Public Utilities Act and any rules or
16765	16765	4 regulations adopted thereunder.
16766	16766	5 (2) Notwithstanding anything to the contrary, an
16767	16767	6 electricity provider shall provide credits for the electricity
16768	16768	7 produced by the projects described in paragraph (1) of this
16769	16769	8 subsection (l). The electricity provider shall provide credits
16770	16770	9 that include at least energy supply, capacity, transmission,
16771	16771	10 and, if applicable, the purchased energy adjustment on the
16772	16772	11 subscriber's monthly bill equal to the subscriber's share of
16773	16773	12 the production of electricity from the project, as determined
16774	16774	13 by paragraph (3) of this subsection (l). For customers with
16775	16775	14 transmission or capacity charges not charged on a
16776	16776	15 kilowatt-hour basis, the electricity provider shall prepare a
16777	16777	16 reasonable approximation of the kilowatt-hour equivalent value
16778	16778	17 and provide that value as a monetary credit. The electricity
16779	16779	18 provider shall submit these approximation methodologies to the
16780	16780	19 Commission for review, modification, and approval.
16781	16781	20 Notwithstanding anything to the contrary, customers on payment
16782	16782	21 plans or participating in budget billing programs shall have
16783	16783	22 credits applied on a monthly basis.
16784	16784	23 (3) Notwithstanding anything to the contrary and
16785	16785	24 regardless of whether a subscriber to an eligible community
16786	16786	25 renewable generation project receives power and energy service
16787	16787	26 from the electric utility or an alternative retail electric
16788	16788
16789	16789
16790	16790
16791	16791
16792	16792
16793	16793	HB3779 - 467 - LRB104 11172 AAS 21254 b
16794	16794
16795	16795
16796	16796	HB3779- 468 -LRB104 11172 AAS 21254 b HB3779 - 468 - LRB104 11172 AAS 21254 b
16797	16797	HB3779 - 468 - LRB104 11172 AAS 21254 b
16798	16798	1 supplier, for projects eligible under paragraph (C) of
16799	16799	2 subparagraph (1) of this subsection (l), electric utilities
16800	16800	3 serving more than 200,000 customers as of January 1, 2021
16801	16801	4 shall provide the monetary credits to a subscriber's
16802	16802	5 subsequent bill for the electricity produced by community
16803	16803	6 renewable generation projects. The electric utility shall
16804	16804	7 provide monetary credits to a subscriber's subsequent bill at
16805	16805	8 the utility's total price to compare equal to the subscriber's
16806	16806	9 share of the production of electricity from the project, as
16807	16807	10 determined by paragraph (5) of this subsection (l). For the
16808	16808	11 purposes of this subsection, "total price to compare" means
16809	16809	12 the rate or rates published by the Illinois Commerce
16810	16810	13 Commission for energy supply for eligible customers receiving
16811	16811	14 supply service from the electric utility, and shall include
16812	16812	15 energy, capacity, transmission, and the purchased energy
16813	16813	16 adjustment. Notwithstanding anything to the contrary,
16814	16814	17 customers on payment plans or participating in budget billing
16815	16815	18 programs shall have credits applied on a monthly basis. Any
16816	16816	19 applicable credit or reduction in load obligation from the
16817	16817	20 production of the community renewable generating projects
16818	16818	21 receiving a credit under this subsection shall be credited to
16819	16819	22 the electric utility to offset the cost of providing the
16820	16820	23 credit. To the extent that the credit or load obligation
16821	16821	24 reduction does not completely offset the cost of providing the
16822	16822	25 credit to subscribers of community renewable generation
16823	16823	26 projects as described in this subsection, the electric utility
16824	16824
16825	16825
16826	16826
16827	16827
16828	16828
16829	16829	HB3779 - 468 - LRB104 11172 AAS 21254 b
16830	16830
16831	16831
16832	16832	HB3779- 469 -LRB104 11172 AAS 21254 b HB3779 - 469 - LRB104 11172 AAS 21254 b
16833	16833	HB3779 - 469 - LRB104 11172 AAS 21254 b
16834	16834	1 may recover the remaining costs through its Multi-Year Rate
16835	16835	2 Plan. All electric utilities serving 200,000 or fewer
16836	16836	3 customers as of January 1, 2021 shall only provide the
16837	16837	4 monetary credits to a subscriber's subsequent bill for the
16838	16838	5 electricity produced by community renewable generation
16839	16839	6 projects if the subscriber receives power and energy service
16840	16840	7 from the electric utility. Alternative retail electric
16841	16841	8 suppliers providing power and energy service to a subscriber
16842	16842	9 located within the service territory of an electric utility
16843	16843	10 not subject to Sections 16-108.18 and 16-118 shall provide the
16844	16844	11 monetary credits to the subscriber's subsequent bill for the
16845	16845	12 electricity produced by community renewable generation
16846	16846	13 projects.
16847	16847	14 (4) If requested by the owner or operator of a community
16848	16848	15 renewable generating project, an electric utility serving more
16849	16849	16 than 200,000 customers as of January 1, 2021 shall enter into a
16850	16850	17 net crediting agreement with the owner or operator to include
16851	16851	18 a subscriber's subscription fee on the subscriber's monthly
16852	16852	19 electric bill and provide the subscriber with a net credit
16853	16853	20 equivalent to the total bill credit value for that generation
16854	16854	21 period minus the subscription fee, provided the subscription
16855	16855	22 fee is structured as a fixed percentage of bill credit value.
16856	16856	23 The net crediting agreement shall set forth payment terms from
16857	16857	24 the electric utility to the owner or operator of the community
16858	16858	25 renewable generating project, and the electric utility may
16859	16859	26 charge a net crediting fee to the owner or operator of a
16860	16860
16861	16861
16862	16862
16863	16863
16864	16864
16865	16865	HB3779 - 469 - LRB104 11172 AAS 21254 b
16866	16866
16867	16867
16868	16868	HB3779- 470 -LRB104 11172 AAS 21254 b HB3779 - 470 - LRB104 11172 AAS 21254 b
16869	16869	HB3779 - 470 - LRB104 11172 AAS 21254 b
16870	16870	1 community renewable generating project that may not exceed 2%
16871	16871	2 of the bill credit value. Notwithstanding anything to the
16872	16872	3 contrary, an electric utility serving 200,000 customers or
16873	16873	4 fewer as of January 1, 2021 shall not be obligated to enter
16874	16874	5 into a net crediting agreement with the owner or operator of a
16875	16875	6 community renewable generating project.
16876	16876	7 (5) For the purposes of facilitating net metering, the
16877	16877	8 owner or operator of the eligible renewable electrical
16878	16878	9 generating facility or community renewable generation project
16879	16879	10 shall be responsible for determining the amount of the credit
16880	16880	11 that each customer or subscriber participating in a project
16881	16881	12 under this subsection (l) is to receive in the following
16882	16882	13 manner:
16883	16883	14 (A) The owner or operator shall, on a monthly basis,
16884	16884	15 provide to the electric utility the kilowatthours of
16885	16885	16 generation attributable to each of the utility's retail
16886	16886	17 customers and subscribers participating in projects under
16887	16887	18 this subsection (l) in accordance with the customer's or
16888	16888	19 subscriber's share of the eligible renewable electric
16889	16889	20 generating facility's or community renewable generation
16890	16890	21 project's output of power and energy for such month. The
16891	16891	22 owner or operator shall electronically transmit such
16892	16892	23 calculations and associated documentation to the electric
16893	16893	24 utility, in a format or method set forth in the applicable
16894	16894	25 tariff, on a monthly basis so that the electric utility
16895	16895	26 can reflect the monetary credits on customers' and
16896	16896
16897	16897
16898	16898
16899	16899
16900	16900
16901	16901	HB3779 - 470 - LRB104 11172 AAS 21254 b
16902	16902
16903	16903
16904	16904	HB3779- 471 -LRB104 11172 AAS 21254 b HB3779 - 471 - LRB104 11172 AAS 21254 b
16905	16905	HB3779 - 471 - LRB104 11172 AAS 21254 b
16906	16906	1 subscribers' electric utility bills. The electric utility
16907	16907	2 shall be permitted to revise its tariffs to implement the
16908	16908	3 provisions of this amendatory Act of the 102nd General
16909	16909	4 Assembly. The owner or operator shall separately provide
16910	16910	5 the electric utility with the documentation detailing the
16911	16911	6 calculations supporting the credit in the manner set forth
16912	16912	7 in the applicable tariff.
16913	16913	8 (B) For those participating customers and subscribers
16914	16914	9 who receive their energy supply from an alternative retail
16915	16915	10 electric supplier, the electric utility shall remit to the
16916	16916	11 applicable alternative retail electric supplier the
16917	16917	12 information provided under subparagraph (A) of this
16918	16918	13 paragraph (3) for such customers and subscribers in a
16919	16919	14 manner set forth in such alternative retail electric
16920	16920	15 supplier's net metering program, or as otherwise agreed
16921	16921	16 between the utility and the alternative retail electric
16922	16922	17 supplier. The alternative retail electric supplier shall
16923	16923	18 then submit to the utility the amount of the charges for
16924	16924	19 power and energy to be applied to such customers and
16925	16925	20 subscribers, including the amount of the credit associated
16926	16926	21 with net metering.
16927	16927	22 (C) A participating customer or subscriber may provide
16928	16928	23 authorization as required by applicable law that directs
16929	16929	24 the electric utility to submit information to the owner or
16930	16930	25 operator of the eligible renewable electrical generating
16931	16931	26 facility or community renewable generation project to
16932	16932
16933	16933
16934	16934
16935	16935
16936	16936
16937	16937	HB3779 - 471 - LRB104 11172 AAS 21254 b
16938	16938
16939	16939
16940	16940	HB3779- 472 -LRB104 11172 AAS 21254 b HB3779 - 472 - LRB104 11172 AAS 21254 b
16941	16941	HB3779 - 472 - LRB104 11172 AAS 21254 b
16942	16942	1 which the customer or subscriber has an ownership or
16943	16943	2 leasehold interest or a subscription. Such information
16944	16944	3 shall be limited to the components of the net metering
16945	16945	4 credit calculated under this subsection (l), including the
16946	16946	5 bill credit rate, total kilowatthours, and total monetary
16947	16947	6 credit value applied to the customer's or subscriber's
16948	16948	7 bill for the monthly billing period.
16949	16949	8 (l-5) Within 90 days after the effective date of this
16950	16950	9 amendatory Act of the 102nd General Assembly, each electric
16951	16951	10 utility subject to this Section shall file a tariff or tariffs
16952	16952	11 to implement the provisions of subsection (l) of this Section,
16953	16953	12 which shall, consistent with the provisions of subsection (l),
16954	16954	13 describe the terms and conditions under which owners or
16955	16955	14 operators of qualifying properties, units, or apartments may
16956	16956	15 participate in net metering. The Commission shall approve, or
16957	16957	16 approve with modification, the tariff within 120 days after
16958	16958	17 the effective date of this amendatory Act of the 102nd General
16959	16959	18 Assembly.
16960	16960	19 (m) Nothing in this Section shall affect the right of an
16961	16961	20 electricity provider to continue to provide, or the right of a
16962	16962	21 retail customer to continue to receive service pursuant to a
16963	16963	22 contract for electric service between the electricity provider
16964	16964	23 and the retail customer in accordance with the prices, terms,
16965	16965	24 and conditions provided for in that contract. Either the
16966	16966	25 electricity provider or the customer may require compliance
16967	16967	26 with the prices, terms, and conditions of the contract.
16968	16968
16969	16969
16970	16970
16971	16971
16972	16972
16973	16973	HB3779 - 472 - LRB104 11172 AAS 21254 b
16974	16974
16975	16975
16976	16976	HB3779- 473 -LRB104 11172 AAS 21254 b HB3779 - 473 - LRB104 11172 AAS 21254 b
16977	16977	HB3779 - 473 - LRB104 11172 AAS 21254 b
16978	16978	1 (n) On and after January 1, 2025, the net metering
16979	16979	2 services described in subsections (d), (d-5), and (e) of this
16980	16980	3 Section shall no longer be offered, except as to those
16981	16981	4 eligible renewable electrical generating facilities for which
16982	16982	5 retail customers are receiving net metering service under
16983	16983	6 these subsections at the time the net metering services under
16984	16984	7 those subsections are no longer offered; those systems shall
16985	16985	8 continue to receive net metering services described in
16986	16986	9 subsections (d), (d-5), and (e) of this Section for the
16987	16987	10 lifetime of the system, regardless of if those retail
16988	16988	11 customers change electricity providers or whether the retail
16989	16989	12 customer benefiting from the system changes. The electric
16990	16990	13 utility serving more than 200,000 customers as of January 1,
16991	16991	14 2021 is responsible for ensuring the billing credits continue
16992	16992	15 without lapse for the lifetime of systems, as required in
16993	16993	16 subsection (o). Those retail customers that begin taking net
16994	16994	17 metering service after the date that net metering services are
16995	16995	18 no longer offered under such subsections shall be subject to
16996	16996	19 the provisions set forth in the following paragraphs (1)
16997	16997	20 through (3) of this subsection (n):
16998	16998	21 (1) An electricity provider shall charge or credit for
16999	16999	22 the net electricity supplied to eligible customers or
17000	17000	23 provided by eligible customers whose electric supply
17001	17001	24 service is not provided based on hourly pricing in the
17002	17002	25 following manner:
17003	17003	26 (A) If the amount of electricity used by the
17004	17004
17005	17005
17006	17006
17007	17007
17008	17008
17009	17009	HB3779 - 473 - LRB104 11172 AAS 21254 b
17010	17010
17011	17011
17012	17012	HB3779- 474 -LRB104 11172 AAS 21254 b HB3779 - 474 - LRB104 11172 AAS 21254 b
17013	17013	HB3779 - 474 - LRB104 11172 AAS 21254 b
17014	17014	1 customer during the monthly billing period exceeds the
17015	17015	2 amount of electricity produced by the customer, then
17016	17016	3 the electricity provider shall charge the customer for
17017	17017	4 the net kilowatt-hour based electricity charges
17018	17018	5 reflected in the customer's electric service rate
17019	17019	6 supplied to and used by the customer as provided in
17020	17020	7 paragraph (3) of this subsection (n).
17021	17021	8 (B) If the amount of electricity produced by a
17022	17022	9 customer during the monthly billing period exceeds the
17023	17023	10 amount of electricity used by the customer during that
17024	17024	11 billing period, then the electricity provider
17025	17025	12 supplying that customer shall apply a 1:1
17026	17026	13 kilowatt-hour energy or monetary credit kilowatt-hour
17027	17027	14 supply charges to the customer's subsequent bill. The
17028	17028	15 customer shall choose between 1:1 kilowatt-hour or
17029	17029	16 monetary credit at the time of application. For the
17030	17030	17 purposes of this subsection, "kilowatt-hour supply
17031	17031	18 charges" means the kilowatt-hour equivalent values for
17032	17032	19 energy, capacity, transmission, and the purchased
17033	17033	20 energy adjustment, if applicable. Notwithstanding
17034	17034	21 anything to the contrary, customers on payment plans
17035	17035	22 or participating in budget billing programs shall have
17036	17036	23 credits applied on a monthly basis. The electricity
17037	17037	24 provider shall continue to carry over any excess
17038	17038	25 kilowatt-hour or monetary energy credits earned and
17039	17039	26 apply those credits to subsequent billing periods. For
17040	17040
17041	17041
17042	17042
17043	17043
17044	17044
17045	17045	HB3779 - 474 - LRB104 11172 AAS 21254 b
17046	17046
17047	17047
17048	17048	HB3779- 475 -LRB104 11172 AAS 21254 b HB3779 - 475 - LRB104 11172 AAS 21254 b
17049	17049	HB3779 - 475 - LRB104 11172 AAS 21254 b
17050	17050	1 customers with transmission or capacity charges not
17051	17051	2 charged on a kilowatt-hour basis, the electricity
17052	17052	3 provider shall prepare a reasonable approximation of
17053	17053	4 the kilowatt-hour equivalent value and provide that
17054	17054	5 value as a monetary credit. The electricity provider
17055	17055	6 shall submit these approximation methodologies to the
17056	17056	7 Commission for review, modification, and approval.
17057	17057	8 (C) (Blank).
17058	17058	9 (2) An electricity provider shall charge or credit for
17059	17059	10 the net electricity supplied to eligible customers or
17060	17060	11 provided by eligible customers whose electric supply
17061	17061	12 service is provided based on hourly pricing in the
17062	17062	13 following manner:
17063	17063	14 (A) If the amount of electricity used by the
17064	17064	15 customer during any hourly period exceeds the amount
17065	17065	16 of electricity produced by the customer, then the
17066	17066	17 electricity provider shall charge the customer for the
17067	17067	18 net electricity supplied to and used by the customer
17068	17068	19 as provided in paragraph (3) of this subsection (n).
17069	17069	20 (B) If the amount of electricity produced by a
17070	17070	21 customer during any hourly period exceeds the amount
17071	17071	22 of electricity used by the customer during that hourly
17072	17072	23 period, the energy provider shall calculate an energy
17073	17073	24 credit for the net kilowatt-hours produced in such
17074	17074	25 period, and shall apply that credit as a monetary
17075	17075	26 credit to the customer's subsequent bill. The value of
17076	17076
17077	17077
17078	17078
17079	17079
17080	17080
17081	17081	HB3779 - 475 - LRB104 11172 AAS 21254 b
17082	17082
17083	17083
17084	17084	HB3779- 476 -LRB104 11172 AAS 21254 b HB3779 - 476 - LRB104 11172 AAS 21254 b
17085	17085	HB3779 - 476 - LRB104 11172 AAS 21254 b
17086	17086	1 the energy credit shall be calculated using the same
17087	17087	2 price per kilowatt-hour as the electric service
17088	17088	3 provider would charge for kilowatt-hour energy sales
17089	17089	4 during that same hourly period and shall also include
17090	17090	5 values for capacity and transmission. For customers
17091	17091	6 with transmission or capacity charges not charged on a
17092	17092	7 kilowatt-hour basis, the electricity provider shall
17093	17093	8 prepare a reasonable approximation of the
17094	17094	9 kilowatt-hour equivalent value and provide that value
17095	17095	10 as a monetary credit. The electricity provider shall
17096	17096	11 submit these approximation methodologies to the
17097	17097	12 Commission for review, modification, and approval.
17098	17098	13 Notwithstanding anything to the contrary, customers on
17099	17099	14 payment plans or participating in budget billing
17100	17100	15 programs shall have credits applied on a monthly
17101	17101	16 basis.
17102	17102	17 (3) An electricity provider shall provide electric
17103	17103	18 service to eligible customers who utilize net metering at
17104	17104	19 non-discriminatory rates that are identical, with respect
17105	17105	20 to rate structure, retail rate components, and any monthly
17106	17106	21 charges, to the rates that the customer would be charged
17107	17107	22 if not a net metering customer. An electricity provider
17108	17108	23 shall charge the customer for the net electricity supplied
17109	17109	24 to and used by the customer according to the terms of the
17110	17110	25 contract or tariff to which the same customer would be
17111	17111	26 assigned or be eligible for if the customer was not a net
17112	17112
17113	17113
17114	17114
17115	17115
17116	17116
17117	17117	HB3779 - 476 - LRB104 11172 AAS 21254 b
17118	17118
17119	17119
17120	17120	HB3779- 477 -LRB104 11172 AAS 21254 b HB3779 - 477 - LRB104 11172 AAS 21254 b
17121	17121	HB3779 - 477 - LRB104 11172 AAS 21254 b
17122	17122	1 metering customer. An electricity provider shall not
17123	17123	2 charge net metering customers any fee or charge or require
17124	17124	3 additional equipment, insurance, or any other requirements
17125	17125	4 not specifically authorized by interconnection standards
17126	17126	5 authorized by the Commission, unless the fee, charge, or
17127	17127	6 other requirement would apply to other similarly situated
17128	17128	7 customers who are not net metering customers. The customer
17129	17129	8 remains responsible for the gross amount of delivery
17130	17130	9 services charges, supply-related charges that are kilowatt
17131	17131	10 based, and all taxes and fees related to such charges. The
17132	17132	11 customer also remains responsible for all taxes and fees
17133	17133	12 that would otherwise be applicable to the net amount of
17134	17134	13 electricity used by the customer. Paragraphs (1) and (2)
17135	17135	14 of this subsection (n) shall not be construed to prevent
17136	17136	15 an arms-length agreement between an electricity provider
17137	17137	16 and an eligible customer that sets forth different prices,
17138	17138	17 terms, and conditions for the provision of net metering
17139	17139	18 service, including, but not limited to, the provision of
17140	17140	19 the appropriate metering equipment for non-residential
17141	17141	20 customers. Nothing in this paragraph (3) shall be
17142	17142	21 interpreted to mandate that a utility that is only
17143	17143	22 required to provide delivery services to a given customer
17144	17144	23 must also sell electricity to such customer.
17145	17145	24 (o) Within 90 days after the effective date of this
17146	17146	25 amendatory Act of the 102nd General Assembly, each electric
17147	17147	26 utility subject to this Section shall file a tariff, which
17148	17148
17149	17149
17150	17150
17151	17151
17152	17152
17153	17153	HB3779 - 477 - LRB104 11172 AAS 21254 b
17154	17154
17155	17155
17156	17156	HB3779- 478 -LRB104 11172 AAS 21254 b HB3779 - 478 - LRB104 11172 AAS 21254 b
17157	17157	HB3779 - 478 - LRB104 11172 AAS 21254 b
17158	17158	1 shall, consistent with the provisions of this Section, propose
17159	17159	2 the terms and conditions under which a customer may
17160	17160	3 participate in net metering. The tariff for electric utilities
17161	17161	4 serving more than 200,000 customers as of January 1, 2021
17162	17162	5 shall also provide a streamlined and transparent bill
17163	17163	6 crediting system for net metering to be managed by the
17164	17164	7 electric utilities. The terms and conditions shall include,
17165	17165	8 but are not limited to, that an electric utility shall manage
17166	17166	9 and maintain billing of net metering credits and charges
17167	17167	10 regardless of if the eligible customer takes net metering
17168	17168	11 under an electric utility or alternative retail electric
17169	17169	12 supplier. The electric utility serving more than 200,000
17170	17170	13 customers as of January 1, 2021 shall process and approve all
17171	17171	14 net metering applications, even if an eligible customer is
17172	17172	15 served by an alternative retail electric supplier; and the
17173	17173	16 utility shall forward application approval to the appropriate
17174	17174	17 alternative retail electric supplier. Eligibility for net
17175	17175	18 metering shall remain with the owner of the utility billing
17176	17176	19 address such that, if an eligible renewable electrical
17177	17177	20 generating facility changes ownership, the net metering
17178	17178	21 eligibility transfers to the new owner. The electric utility
17179	17179	22 serving more than 200,000 customers as of January 1, 2021
17180	17180	23 shall manage net metering billing for eligible customers to
17181	17181	24 ensure full crediting occurs on electricity bills, including,
17182	17182	25 but not limited to, ensuring net metering crediting begins
17183	17183	26 upon commercial operation date, net metering billing transfers
17184	17184
17185	17185
17186	17186
17187	17187
17188	17188
17189	17189	HB3779 - 478 - LRB104 11172 AAS 21254 b
17190	17190
17191	17191
17192	17192	HB3779- 479 -LRB104 11172 AAS 21254 b HB3779 - 479 - LRB104 11172 AAS 21254 b
17193	17193	HB3779 - 479 - LRB104 11172 AAS 21254 b
17194	17194	1 immediately if an eligible customer switches from an electric
17195	17195	2 utility to alternative retail electric supplier or vice versa,
17196	17196	3 and net metering billing transfers between ownership of a
17197	17197	4 valid billing address. All transfers referenced in the
17198	17198	5 preceding sentence shall include transfer of all banked
17199	17199	6 credits. All electric utilities serving 200,000 or fewer
17200	17200	7 customers as of January 1, 2021 shall manage net metering
17201	17201	8 billing for eligible customers receiving power and energy
17202	17202	9 service from the electric utility to ensure full crediting
17203	17203	10 occurs on electricity bills, ensuring net metering crediting
17204	17204	11 begins upon commercial operation date, net metering billing
17205	17205	12 transfers immediately if an eligible customer switches from an
17206	17206	13 electric utility to alternative retail electric supplier or
17207	17207	14 vice versa, and net metering billing transfers between
17208	17208	15 ownership of a valid billing address. Alternative retail
17209	17209	16 electric suppliers providing power and energy service to
17210	17210	17 eligible customers located within the service territory of an
17211	17211	18 electric utility serving 200,000 or fewer customers as of
17212	17212	19 January 1, 2021 shall manage net metering billing for eligible
17213	17213	20 customers to ensure full crediting occurs on electricity
17214	17214	21 bills, including, but not limited to, ensuring net metering
17215	17215	22 crediting begins upon commercial operation date, net metering
17216	17216	23 billing transfers immediately if an eligible customer switches
17217	17217	24 from an electric utility to alternative retail electric
17218	17218	25 supplier or vice versa, and net metering billing transfers
17219	17219	26 between ownership of a valid billing address.
17220	17220
17221	17221
17222	17222
17223	17223
17224	17224
17225	17225	HB3779 - 479 - LRB104 11172 AAS 21254 b
17226	17226
17227	17227
17228	17228	HB3779- 480 -LRB104 11172 AAS 21254 b HB3779 - 480 - LRB104 11172 AAS 21254 b
17229	17229	HB3779 - 480 - LRB104 11172 AAS 21254 b
17230	17230	1 (Source: P.A. 102-662, eff. 9-15-21.)
17231	17231	2 (220 ILCS 5/16-107.6)
17232	17232	3 Sec. 16-107.6. Distributed generation rebate.
17233	17233	4 (a) In this Section:
17234	17234	5 "Additive services" means the services that distributed
17235	17235	6 energy resources provide to the energy system and society that
17236	17236	7 are not (1) already included in the base rebates for
17237	17237	8 system-wide grid services; or (2) otherwise already
17238	17238	9 compensated. Additive services may reflect, but shall not be
17239	17239	10 limited to, any geographic, time-based, performance-based, and
17240	17240	11 other benefits of distributed energy resources, as well as the
17241	17241	12 present and future technological capabilities of distributed
17242	17242	13 energy resources and present and future grid needs.
17243	17243	14 "Distributed energy resource" means a wide range of
17244	17244	15 technologies that are located on the customer side of the
17245	17245	16 customer's electric meter, including, but not limited to,
17246	17246	17 distributed generation, energy storage, electric vehicles, and
17247	17247	18 demand response technologies.
17248	17248	19 "Energy storage system" means commercially available
17249	17249	20 technology that is capable of absorbing energy and storing it
17250	17250	21 for a period of time for use at a later time, including, but
17251	17251	22 not limited to, electrochemical, thermal, and
17252	17252	23 electromechanical technologies, and may be interconnected
17253	17253	24 behind the customer's meter or interconnected behind its own
17254	17254	25 meter.
17255	17255
17256	17256
17257	17257
17258	17258
17259	17259
17260	17260	HB3779 - 480 - LRB104 11172 AAS 21254 b
17261	17261
17262	17262
17263	17263	HB3779- 481 -LRB104 11172 AAS 21254 b HB3779 - 481 - LRB104 11172 AAS 21254 b
17264	17264	HB3779 - 481 - LRB104 11172 AAS 21254 b
17265	17265	1 "Smart inverter" means a device that converts direct
17266	17266	2 current into alternating current and meets the IEEE 1547-2018
17267	17267	3 equipment standards. Until devices that meet the IEEE
17268	17268	4 1547-2018 standard are available, devices that meet the UL
17269	17269	5 1741 SA standard are acceptable.
17270	17270	6 "Subscriber" has the meaning set forth in Section 1-10 of
17271	17271	7 the Illinois Power Agency Act.
17272	17272	8 "Subscription" has the meaning set forth in Section 1-10
17273	17273	9 of the Illinois Power Agency Act.
17274	17274	10 "System-wide grid services" means the benefits that a
17275	17275	11 distributed energy resource provides to the distribution grid
17276	17276	12 for a period of no less than 25 years. System-wide grid
17277	17277	13 services do not vary by location, time, or the performance
17278	17278	14 characteristics of the distributed energy resource.
17279	17279	15 System-wide grid services include, but are not limited to,
17280	17280	16 avoided or deferred distribution capacity costs, resilience
17281	17281	17 and reliability benefits, avoided or deferred distribution
17282	17282	18 operation and maintenance costs, distribution voltage and
17283	17283	19 power quality benefits, and line loss reductions.
17284	17284	20 "Threshold date" means December 31, 2024 or the date on
17285	17285	21 which the utility's tariff or tariffs setting the new
17286	17286	22 compensation values established under subsection (e) take
17287	17287	23 effect, whichever is later.
17288	17288	24 (b) An electric utility that serves more than 200,000
17289	17289	25 customers in the State shall file a petition with the
17290	17290	26 Commission requesting approval of the utility's tariff to
17291	17291
17292	17292
17293	17293
17294	17294
17295	17295
17296	17296	HB3779 - 481 - LRB104 11172 AAS 21254 b
17297	17297
17298	17298
17299	17299	HB3779- 482 -LRB104 11172 AAS 21254 b HB3779 - 482 - LRB104 11172 AAS 21254 b
17300	17300	HB3779 - 482 - LRB104 11172 AAS 21254 b
17301	17301	1 provide a rebate to the owner or operator of distributed
17302	17302	2 generation, including third-party owned systems, that meets
17303	17303	3 the following criteria:
17304	17304	4 (1) has a nameplate generating capacity no greater
17305	17305	5 than 5,000 kilowatts and is primarily used to offset a
17306	17306	6 customer's electricity load;
17307	17307	7 (2) is located on the customer's side of the billing
17308	17308	8 meter and for the customer's own use;
17309	17309	9 (3) is interconnected to electric distribution
17310	17310	10 facilities owned by the electric utility under rules
17311	17311	11 adopted by the Commission by means of the inverter or
17312	17312	12 smart inverter required by this Section, as applicable.
17313	17313	13 For purposes of this Section, "distributed generation"
17314	17314	14 shall satisfy the definition of distributed renewable energy
17315	17315	15 generation device set forth in Section 1-10 of the Illinois
17316	17316	16 Power Agency Act to the extent such definition is consistent
17317	17317	17 with the requirements of this Section.
17318	17318	18 In addition, any new photovoltaic distributed generation
17319	17319	19 that is installed after June 1, 2017 (the effective date of
17320	17320	20 Public Act 99-906) must be installed by a qualified person, as
17321	17321	21 defined by subsection (i) of Section 1-56 of the Illinois
17322	17322	22 Power Agency Act.
17323	17323	23 The tariff shall include a base rebate that compensates
17324	17324	24 distributed generation for the system-wide grid services
17325	17325	25 associated with distributed generation and, after the
17326	17326	26 proceeding described in subsection (e) of this Section, an
17327	17327
17328	17328
17329	17329
17330	17330
17331	17331
17332	17332	HB3779 - 482 - LRB104 11172 AAS 21254 b
17333	17333
17334	17334
17335	17335	HB3779- 483 -LRB104 11172 AAS 21254 b HB3779 - 483 - LRB104 11172 AAS 21254 b
17336	17336	HB3779 - 483 - LRB104 11172 AAS 21254 b
17337	17337	1 additional payment or payments for the additive services. The
17338	17338	2 tariff shall provide that the smart inverter associated with
17339	17339	3 the distributed generation shall provide autonomous response
17340	17340	4 to grid conditions through its default settings as approved by
17341	17341	5 the Commission. Default settings may not be changed after the
17342	17342	6 execution of the interconnection agreement except by mutual
17343	17343	7 agreement between the utility and the owner or operator of the
17344	17344	8 distributed generation. Nothing in this Section shall negate
17345	17345	9 or supersede Institute of Electrical and Electronics Engineers
17346	17346	10 equipment standards or other similar standards or
17347	17347	11 requirements. The tariff shall not limit the ability of the
17348	17348	12 smart inverter or other distributed energy resource to provide
17349	17349	13 wholesale market products such as regulation, demand response,
17350	17350	14 or other services, or limit the ability of the owner of the
17351	17351	15 smart inverter or the other distributed energy resource to
17352	17352	16 receive compensation for providing those wholesale market
17353	17353	17 products or services.
17354	17354	18 (b-5) Within 30 days after the effective date of this
17355	17355	19 amendatory Act of the 102nd General Assembly, each electric
17356	17356	20 public utility with 3,000,000 or more retail customers shall
17357	17357	21 file a tariff with the Commission that further compensates any
17358	17358	22 retail customer that installs or has installed photovoltaic
17359	17359	23 facilities paired with energy storage facilities on or
17360	17360	24 adjacent to its premises for the benefits the facilities
17361	17361	25 provide to the distribution grid. The tariff shall provide
17362	17362	26 that, in addition to the other rebates identified in this
17363	17363
17364	17364
17365	17365
17366	17366
17367	17367
17368	17368	HB3779 - 483 - LRB104 11172 AAS 21254 b
17369	17369
17370	17370
17371	17371	HB3779- 484 -LRB104 11172 AAS 21254 b HB3779 - 484 - LRB104 11172 AAS 21254 b
17372	17372	HB3779 - 484 - LRB104 11172 AAS 21254 b
17373	17373	1 Section, the electric utility shall rebate to such retail
17374	17374	2 customer (i) the previously incurred and future costs of
17375	17375	3 installing interconnection facilities and related
17376	17376	4 infrastructure to enable full participation in the PJM
17377	17377	5 Interconnection, LLC or its successor organization frequency
17378	17378	6 regulation market; and (ii) all wholesale demand charges
17379	17379	7 incurred after the effective date of this amendatory Act of
17380	17380	8 the 102nd General Assembly. The Commission shall approve, or
17381	17381	9 approve with modification, the tariff within 120 days after
17382	17382	10 the utility's filing.
17383	17383	11 (c) The proposed tariff authorized by subsection (b) of
17384	17384	12 this Section shall include the following participation terms
17385	17385	13 for rebates to be applied under this Section for distributed
17386	17386	14 generation that satisfies the criteria set forth in subsection
17387	17387	15 (b) of this Section:
17388	17388	16 (1) The owner or operator of distributed generation
17389	17389	17 that services customers not eligible for net metering
17390	17390	18 under subsection (d), (d-5), or (e) of Section 16-107.5 of
17391	17391	19 this Act may apply for a rebate as provided for in this
17392	17392	20 Section. Until the threshold date, the value of the rebate
17393	17393	21 shall be $250 per kilowatt of nameplate generating
17394	17394	22 capacity, measured as nominal DC power output, of that
17395	17395	23 customer's distributed generation. To the extent the
17396	17396	24 distributed generation also has an associated energy
17397	17397	25 storage, then the energy storage system shall be
17398	17398	26 separately compensated with a base rebate of $250 per
17399	17399
17400	17400
17401	17401
17402	17402
17403	17403
17404	17404	HB3779 - 484 - LRB104 11172 AAS 21254 b
17405	17405
17406	17406
17407	17407	HB3779- 485 -LRB104 11172 AAS 21254 b HB3779 - 485 - LRB104 11172 AAS 21254 b
17408	17408	HB3779 - 485 - LRB104 11172 AAS 21254 b
17409	17409	1 kilowatt-hour of nameplate capacity. Any distributed
17410	17410	2 generation device that is compensated for storage in this
17411	17411	3 subsection (1) before the threshold date shall participate
17412	17412	4 in one or more programs determined through the Multi-Year
17413	17413	5 Integrated Grid Planning process that are designed to meet
17414	17414	6 peak reduction and flexibility. After the threshold date,
17415	17415	7 the value of the base rebate and additional compensation
17416	17416	8 for any additive services shall be as determined by the
17417	17417	9 Commission in the proceeding described in subsection (e)
17418	17418	10 of this Section, provided that the value of the base
17419	17419	11 rebate for system-wide grid services shall not be lower
17420	17420	12 than $250 per kilowatt of nameplate generating capacity of
17421	17421	13 distributed generation or community renewable generation
17422	17422	14 project.
17423	17423	15 (2) The owner or operator of distributed generation
17424	17424	16 that, before the threshold date, would have been eligible
17425	17425	17 for net metering under subsection (d), (d-5), or (e) of
17426	17426	18 Section 16-107.5 of this Act and that has not previously
17427	17427	19 received a distributed generation rebate, may apply for a
17428	17428	20 rebate as provided for in this Section. Until the
17429	17429	21 threshold date, the value of the base rebate shall be $300
17430	17430	22 per kilowatt of nameplate generating capacity, measured as
17431	17431	23 nominal DC power output, of the distributed generation.
17432	17432	24 The owner or operator of distributed generation that,
17433	17433	25 before the threshold date, is eligible for net metering
17434	17434	26 under subsection (d), (d-5), or (e) of Section 16-107.5 of
17435	17435
17436	17436
17437	17437
17438	17438
17439	17439
17440	17440	HB3779 - 485 - LRB104 11172 AAS 21254 b
17441	17441
17442	17442
17443	17443	HB3779- 486 -LRB104 11172 AAS 21254 b HB3779 - 486 - LRB104 11172 AAS 21254 b
17444	17444	HB3779 - 486 - LRB104 11172 AAS 21254 b
17445	17445	1 this Act may apply for a base rebate for an energy storage
17446	17446	2 device that uses the same smart inverter as the
17447	17447	3 distributed generation, regardless of whether the
17448	17448	4 distributed generation applies for a rebate for the
17449	17449	5 distributed generation device. The energy storage system
17450	17450	6 shall be separately compensated at a base payment of $300
17451	17451	7 per kilowatt-hour of nameplate capacity. Any distributed
17452	17452	8 generation device that is compensated for storage in this
17453	17453	9 subsection (2) before the threshold date shall participate
17454	17454	10 in a Virtual Power Plant Program defined in Section
17455	17455	11 16.107.9 an a peak time rebate program, hourly pricing
17456	17456	12 program, or time-of-use rate program offered by the
17457	17457	13 applicable electric utility. After the threshold date, the
17458	17458	14 value of the base rebate and additional compensation for
17459	17459	15 any additive services shall be as determined by the
17460	17460	16 Commission in the proceeding described in subsection (e)
17461	17461	17 of this Section, provided that, prior to December 31,
17462	17462	18 2029, the value of the base rebate for system-wide
17463	17463	19 services shall not be lower than $300 per kilowatt of
17464	17464	20 nameplate generating capacity of distributed generation,
17465	17465	21 after which it shall not be lower than $250 per kilowatt of
17466	17466	22 nameplate capacity.
17467	17467	23 (3) Upon approval of a rebate application submitted
17468	17468	24 under this subsection (c), the retail customer shall no
17469	17469	25 longer be entitled to receive any delivery service credits
17470	17470	26 for the excess electricity generated by its facility and
17471	17471
17472	17472
17473	17473
17474	17474
17475	17475
17476	17476	HB3779 - 486 - LRB104 11172 AAS 21254 b
17477	17477
17478	17478
17479	17479	HB3779- 487 -LRB104 11172 AAS 21254 b HB3779 - 487 - LRB104 11172 AAS 21254 b
17480	17480	HB3779 - 487 - LRB104 11172 AAS 21254 b
17481	17481	1 shall be subject to the provisions of subsection (n) of
17482	17482	2 Section 16-107.5 of this Act unless the owner or operator
17483	17483	3 receives a rebate only for an energy storage device and
17484	17484	4 not for the distributed generation device.
17485	17485	5 (4) To be eligible for a rebate described in this
17486	17486	6 subsection (c), the owner or operator of the distributed
17487	17487	7 generation must have a smart inverter installed and in
17488	17488	8 operation on the distributed generation.
17489	17489	9 (d) The Commission shall review the proposed tariff
17490	17490	10 authorized by subsection (b) of this Section and may make
17491	17491	11 changes to the tariff that are consistent with this Section
17492	17492	12 and with the Commission's authority under Article IX of this
17493	17493	13 Act, subject to notice and hearing. Following notice and
17494	17494	14 hearing, the Commission shall issue an order approving, or
17495	17495	15 approving with modification, such tariff no later than 240
17496	17496	16 days after the utility files its tariff. Upon the effective
17497	17497	17 date of this amendatory Act of the 102nd General Assembly, an
17498	17498	18 electric utility shall file a petition with the Commission to
17499	17499	19 amend and update any existing tariffs to comply with
17500	17500	20 subsections (b) and (c).
17501	17501	21 (e) By no later than June 30, 2023, the Commission shall
17502	17502	22 open an independent, statewide investigation into the value
17503	17503	23 of, and compensation for, distributed energy resources. The
17504	17504	24 Commission shall conduct the investigation, but may arrange
17505	17505	25 for experts or consultants independent of the utilities and
17506	17506	26 selected by the Commission to assist with the investigation.
17507	17507
17508	17508
17509	17509
17510	17510
17511	17511
17512	17512	HB3779 - 487 - LRB104 11172 AAS 21254 b
17513	17513
17514	17514
17515	17515	HB3779- 488 -LRB104 11172 AAS 21254 b HB3779 - 488 - LRB104 11172 AAS 21254 b
17516	17516	HB3779 - 488 - LRB104 11172 AAS 21254 b
17517	17517	1 The cost of the investigation shall be shared by the utilities
17518	17518	2 filing tariffs under subsection (b) of this Section but may be
17519	17519	3 recovered as an expense through normal ratemaking procedures.
17520	17520	4 (1) The Commission shall ensure that the investigation
17521	17521	5 includes, at minimum, diverse sets of stakeholders; a
17522	17522	6 review of best practices in calculating the value of
17523	17523	7 distributed energy resource benefits; a review of the full
17524	17524	8 value of the distributed energy resources and the manner
17525	17525	9 in which each component of that value is or is not
17526	17526	10 otherwise compensated; and assessments of how the value of
17527	17527	11 distributed energy resources may evolve based on the
17528	17528	12 present and future technological capabilities of
17529	17529	13 distributed energy resources and based on present and
17530	17530	14 future grid needs.
17531	17531	15 (2) The Commission's final order concluding this
17532	17532	16 investigation shall establish an annual process and
17533	17533	17 formula for the compensation of distributed generation and
17534	17534	18 energy storage systems, and an initial set of inputs for
17535	17535	19 that formula. The Commission's final order concluding this
17536	17536	20 investigation shall establish base rebates that compensate
17537	17537	21 distributed generation, community renewable generation
17538	17538	22 projects and energy storage systems for the system-wide
17539	17539	23 grid services that they provide. Those base rebate values
17540	17540	24 shall be consistent across the state, and shall not vary
17541	17541	25 by customer, customer class, customer location, or any
17542	17542	26 other variable. With respect to rebates for distributed
17543	17543
17544	17544
17545	17545
17546	17546
17547	17547
17548	17548	HB3779 - 488 - LRB104 11172 AAS 21254 b
17549	17549
17550	17550
17551	17551	HB3779- 489 -LRB104 11172 AAS 21254 b HB3779 - 489 - LRB104 11172 AAS 21254 b
17552	17552	HB3779 - 489 - LRB104 11172 AAS 21254 b
17553	17553	1 generation or community renewable generation projects,
17554	17554	2 that rebate shall not be lower than $250 per kilowatt of
17555	17555	3 nameplate generating capacity of the distributed
17556	17556	4 generation or community renewable generation project. The
17557	17557	5 Commission's final order concluding this proceeding shall
17558	17558	6 also direct the utilities to update the formula, on an
17559	17559	7 annual basis, with inputs derived from their integrated
17560	17560	8 grid plans developed pursuant to Section 16-105.17. The
17561	17561	9 base rebate shall be updated annually based on the annual
17562	17562	10 updates to the formula inputs, but, with respect to
17563	17563	11 rebates for distributed generation or community renewable
17564	17564	12 generation projects, shall be no lower than $250 per
17565	17565	13 kilowatt of nameplate generating capacity of the
17566	17566	14 distributed generation or community renewable generation
17567	17567	15 project.
17568	17568	16 (3) The Commission shall also determine, as a part of
17569	17569	17 its investigation under this subsection, whether
17570	17570	18 distributed energy resources can provide any additive
17571	17571	19 services. Those additive services may include services
17572	17572	20 that are provided through utility-controlled responses to
17573	17573	21 grid conditions. If the Commission determines that
17574	17574	22 distributed energy resources can provide additive grid
17575	17575	23 services, the Commission shall determine the terms and
17576	17576	24 conditions for the operation and compensation of those
17577	17577	25 services. That compensation shall be above and beyond the
17578	17578	26 base rebate that the distributed energy generation,
17579	17579
17580	17580
17581	17581
17582	17582
17583	17583
17584	17584	HB3779 - 489 - LRB104 11172 AAS 21254 b
17585	17585
17586	17586
17587	17587	HB3779- 490 -LRB104 11172 AAS 21254 b HB3779 - 490 - LRB104 11172 AAS 21254 b
17588	17588	HB3779 - 490 - LRB104 11172 AAS 21254 b
17589	17589	1 community renewable generation project and energy storage
17590	17590	2 system receives. Compensation for additive services may
17591	17591	3 vary by location, time, performance characteristics,
17592	17592	4 technology types, or other variables.
17593	17593	5 (4) The Commission shall ensure that compensation for
17594	17594	6 distributed energy resources, including base rebates and
17595	17595	7 any payments for additive services, shall reflect all
17596	17596	8 reasonably known and measurable values of the distributed
17597	17597	9 generation over its full expected useful life.
17598	17598	10 Compensation for additive services shall reflect, but
17599	17599	11 shall not be limited to, any geographic, time-based,
17600	17600	12 performance-based, and other benefits of distributed
17601	17601	13 generation, as well as the present and future
17602	17602	14 technological capabilities of distributed energy resources
17603	17603	15 and present and future grid needs.
17604	17604	16 (5) The Commission shall consider the electric
17605	17605	17 utility's integrated grid plan developed pursuant to
17606	17606	18 Section 16-105.17 of this Act to help identify the value
17607	17607	19 of distributed energy resources for the purpose of
17608	17608	20 calculating the compensation described in this subsection.
17609	17609	21 (6) The Commission shall determine additional
17610	17610	22 compensation for distributed energy resources that creates
17611	17611	23 savings and value on the distribution system by being
17612	17612	24 co-located or in close proximity to electric vehicle
17613	17613	25 charging infrastructure in use by medium-duty and
17614	17614	26 heavy-duty vehicles, primarily serving environmental
17615	17615
17616	17616
17617	17617
17618	17618
17619	17619
17620	17620	HB3779 - 490 - LRB104 11172 AAS 21254 b
17621	17621
17622	17622
17623	17623	HB3779- 491 -LRB104 11172 AAS 21254 b HB3779 - 491 - LRB104 11172 AAS 21254 b
17624	17624	HB3779 - 491 - LRB104 11172 AAS 21254 b
17625	17625	1 justice communities, as outlined in the utility integrated
17626	17626	2 grid planning process under Section 16-105.17 of this Act.
17627	17627	3 No later than 60 days after the Commission enters its
17628	17628	4 final order under this subsection (e), each utility shall file
17629	17629	5 its updated tariff or tariffs in compliance with the order,
17630	17630	6 including new tariffs for the recovery of costs incurred under
17631	17631	7 this subsection (e) that shall provide for volumetric-based
17632	17632	8 cost recovery, and the Commission shall approve, or approve
17633	17633	9 with modification, the tariff or tariffs within 240 days after
17634	17634	10 the utility's filing.
17635	17635	11 (f) Notwithstanding any provision of this Act to the
17636	17636	12 contrary, the owner or operator of a community renewable
17637	17637	13 generation project as defined in Section 1-10 of the Illinois
17638	17638	14 Power Agency Act shall also be eligible to apply for the rebate
17639	17639	15 described in this Section. The owner or operator of the
17640	17640	16 community renewable generation project may apply for a rebate
17641	17641	17 only if the owner or operator, or previous owner or operator,
17642	17642	18 of the community renewable generation project has not already
17643	17643	19 submitted an application, and, regardless of whether the
17644	17644	20 subscriber is a residential or non-residential customer, may
17645	17645	21 be allowed the amount identified in paragraph (1) of
17646	17646	22 subsection (c) applicable on the date that the application is
17647	17647	23 submitted.
17648	17648	24 (g) The owner of the distributed generation or community
17649	17649	25 renewable generation project may apply for the rebate or
17650	17650	26 rebates approved under this Section at the time of execution
17651	17651
17652	17652
17653	17653
17654	17654
17655	17655
17656	17656	HB3779 - 491 - LRB104 11172 AAS 21254 b
17657	17657
17658	17658
17659	17659	HB3779- 492 -LRB104 11172 AAS 21254 b HB3779 - 492 - LRB104 11172 AAS 21254 b
17660	17660	HB3779 - 492 - LRB104 11172 AAS 21254 b
17661	17661	1 of an interconnection agreement with the distribution utility
17662	17662	2 and shall receive the value available at that time of
17663	17663	3 execution of the interconnection agreement, provided the
17664	17664	4 project reaches mechanical completion within 24 months after
17665	17665	5 execution of the interconnection agreement. If the project has
17666	17666	6 not reached mechanical completion within 24 months after
17667	17667	7 execution, the owner may reapply for the rebate or rebates
17668	17668	8 approved under this Section available at the time of
17669	17669	9 application and shall receive the value available at the time
17670	17670	10 of application. The utility shall issue the rebate no later
17671	17671	11 than 60 days after the project is energized. In the event the
17672	17672	12 application is incomplete or the utility is otherwise unable
17673	17673	13 to calculate the payment based on the information provided by
17674	17674	14 the owner, the utility shall issue the payment no later than 60
17675	17675	15 days after the application is complete or all requested
17676	17676	16 information is received.
17677	17677	17 (h) An electric utility shall recover from its retail
17678	17678	18 customers all of the costs of the rebates made under a tariff
17679	17679	19 or tariffs approved under subsection (d) of this Section,
17680	17680	20 including, but not limited to, the value of the rebates and all
17681	17681	21 costs incurred by the utility to comply with and implement
17682	17682	22 subsections (b) and (c) of this Section, but not including
17683	17683	23 costs incurred by the utility to comply with and implement
17684	17684	24 subsection (e) of this Section, consistent with the following
17685	17685	25 provisions:
17686	17686	26 (1) The utility shall defer the full amount of its
17687	17687
17688	17688
17689	17689
17690	17690
17691	17691
17692	17692	HB3779 - 492 - LRB104 11172 AAS 21254 b
17693	17693
17694	17694
17695	17695	HB3779- 493 -LRB104 11172 AAS 21254 b HB3779 - 493 - LRB104 11172 AAS 21254 b
17696	17696	HB3779 - 493 - LRB104 11172 AAS 21254 b
17697	17697	1 costs as a regulatory asset. The total costs deferred as a
17698	17698	2 regulatory asset shall be amortized over a 15-year period.
17699	17699	3 The unamortized balance shall be recognized as of December
17700	17700	4 31 for a given year. The utility shall also earn a return
17701	17701	5 on the total of the unamortized balance of the regulatory
17702	17702	6 assets, less any deferred taxes related to the unamortized
17703	17703	7 balance, at an annual rate equal to the utility's weighted
17704	17704	8 average cost of capital that includes, based on a year-end
17705	17705	9 capital structure, the utility's actual cost of debt for
17706	17706	10 the applicable calendar year and a cost of equity, which
17707	17707	11 shall be calculated as the sum of (i) the average for the
17708	17708	12 applicable calendar year of the monthly average yields of
17709	17709	13 30-year U.S. Treasury bonds published by the Board of
17710	17710	14 Governors of the Federal Reserve System in its weekly H.15
17711	17711	15 Statistical Release or successor publication; and (ii) 580
17712	17712	16 basis points, including a revenue conversion factor
17713	17713	17 calculated to recover or refund all additional income
17714	17714	18 taxes that may be payable or receivable as a result of that
17715	17715	19 return.
17716	17716	20 When an electric utility creates a regulatory asset
17717	17717	21 under the provisions of this paragraph (1) of subsection
17718	17718	22 (h), the costs are recovered over a period during which
17719	17719	23 customers also receive a benefit, which is in the public
17720	17720	24 interest. Accordingly, it is the intent of the General
17721	17721	25 Assembly that an electric utility that elects to create a
17722	17722	26 regulatory asset under the provisions of this paragraph
17723	17723
17724	17724
17725	17725
17726	17726
17727	17727
17728	17728	HB3779 - 493 - LRB104 11172 AAS 21254 b
17729	17729
17730	17730
17731	17731	HB3779- 494 -LRB104 11172 AAS 21254 b HB3779 - 494 - LRB104 11172 AAS 21254 b
17732	17732	HB3779 - 494 - LRB104 11172 AAS 21254 b
17733	17733	1 (1) shall recover all of the associated costs, including,
17734	17734	2 but not limited to, its cost of capital as set forth in
17735	17735	3 this paragraph (1). After the Commission has approved the
17736	17736	4 prudence and reasonableness of the costs that comprise the
17737	17737	5 regulatory asset, the electric utility shall be permitted
17738	17738	6 to recover all such costs, and the value and
17739	17739	7 recoverability through rates of the associated regulatory
17740	17740	8 asset shall not be limited, altered, impaired, or reduced.
17741	17741	9 To enable the financing of the incremental capital
17742	17742	10 expenditures, including regulatory assets, for electric
17743	17743	11 utilities that serve less than 3,000,000 retail customers
17744	17744	12 but more than 500,000 retail customers in the State, the
17745	17745	13 utility's actual year-end capital structure that includes
17746	17746	14 a common equity ratio, excluding goodwill, of up to and
17747	17747	15 including 50% of the total capital structure shall be
17748	17748	16 deemed reasonable and used to set rates.
17749	17749	17 (2) The utility, at its election, may recover all of
17750	17750	18 the costs as part of a filing for a general increase in
17751	17751	19 rates under Article IX of this Act, as part of an annual
17752	17752	20 filing to update a performance-based formula rate under
17753	17753	21 subsection (d) of Section 16-108.5 of this Act, or through
17754	17754	22 an automatic adjustment clause tariff, provided that
17755	17755	23 nothing in this paragraph (2) permits the double recovery
17756	17756	24 of such costs from customers. If the utility elects to
17757	17757	25 recover the costs it incurs under subsections (b) and (c)
17758	17758	26 through an automatic adjustment clause tariff, the utility
17759	17759
17760	17760
17761	17761
17762	17762
17763	17763
17764	17764	HB3779 - 494 - LRB104 11172 AAS 21254 b
17765	17765
17766	17766
17767	17767	HB3779- 495 -LRB104 11172 AAS 21254 b HB3779 - 495 - LRB104 11172 AAS 21254 b
17768	17768	HB3779 - 495 - LRB104 11172 AAS 21254 b
17769	17769	1 may file its proposed tariff together with the tariff it
17770	17770	2 files under subsection (b) of this Section or at a later
17771	17771	3 time. The proposed tariff shall provide for an annual
17772	17772	4 reconciliation, less any deferred taxes related to the
17773	17773	5 reconciliation, with interest at an annual rate of return
17774	17774	6 equal to the utility's weighted average cost of capital as
17775	17775	7 calculated under paragraph (1) of this subsection (h),
17776	17776	8 including a revenue conversion factor calculated to
17777	17777	9 recover or refund all additional income taxes that may be
17778	17778	10 payable or receivable as a result of that return, of the
17779	17779	11 revenue requirement reflected in rates for each calendar
17780	17780	12 year, beginning with the calendar year in which the
17781	17781	13 utility files its automatic adjustment clause tariff under
17782	17782	14 this subsection (h), with what the revenue requirement
17783	17783	15 would have been had the actual cost information for the
17784	17784	16 applicable calendar year been available at the filing
17785	17785	17 date. The Commission shall review the proposed tariff and
17786	17786	18 may make changes to the tariff that are consistent with
17787	17787	19 this Section and with the Commission's authority under
17788	17788	20 Article IX of this Act, subject to notice and hearing.
17789	17789	21 Following notice and hearing, the Commission shall issue
17790	17790	22 an order approving, or approving with modification, such
17791	17791	23 tariff no later than 240 days after the utility files its
17792	17792	24 tariff.
17793	17793	25 (i) An electric utility shall recover from its retail
17794	17794	26 customers, on a volumetric basis, all of the costs of the
17795	17795
17796	17796
17797	17797
17798	17798
17799	17799
17800	17800	HB3779 - 495 - LRB104 11172 AAS 21254 b
17801	17801
17802	17802
17803	17803	HB3779- 496 -LRB104 11172 AAS 21254 b HB3779 - 496 - LRB104 11172 AAS 21254 b
17804	17804	HB3779 - 496 - LRB104 11172 AAS 21254 b
17805	17805	1 rebates made under a tariff or tariffs placed into effect
17806	17806	2 under subsection (e) of this Section, including, but not
17807	17807	3 limited to, the value of the rebates and all costs incurred by
17808	17808	4 the utility to comply with and implement subsection (e) of
17809	17809	5 this Section, consistent with the following provisions:
17810	17810	6 (1) The utility may defer a portion of its costs as a
17811	17811	7 regulatory asset. The Commission shall determine the
17812	17812	8 portion that may be appropriately deferred as a regulatory
17813	17813	9 asset. Factors that the Commission shall consider in
17814	17814	10 determining the portion of costs that shall be deferred as
17815	17815	11 a regulatory asset include, but are not limited to: (i)
17816	17816	12 whether and the extent to which a cost effectively
17817	17817	13 deferred or avoided other distribution system operating
17818	17818	14 costs or capital expenditures; (ii) the extent to which a
17819	17819	15 cost provides environmental benefits; (iii) the extent to
17820	17820	16 which a cost improves system reliability or resilience;
17821	17821	17 (iv) the electric utility's distribution system plan
17822	17822	18 developed pursuant to Section 16-105.17 of this Act; (v)
17823	17823	19 the extent to which a cost advances equity principles; and
17824	17824	20 (vi) such other factors as the Commission deems
17825	17825	21 appropriate. The remainder of costs shall be deemed an
17826	17826	22 operating expense and shall be recoverable if found
17827	17827	23 prudent and reasonable by the Commission.
17828	17828	24 The total costs deferred as a regulatory asset shall
17829	17829	25 be amortized over a 15-year period. The unamortized
17830	17830	26 balance shall be recognized as of December 31 for a given
17831	17831
17832	17832
17833	17833
17834	17834
17835	17835
17836	17836	HB3779 - 496 - LRB104 11172 AAS 21254 b
17837	17837
17838	17838
17839	17839	HB3779- 497 -LRB104 11172 AAS 21254 b HB3779 - 497 - LRB104 11172 AAS 21254 b
17840	17840	HB3779 - 497 - LRB104 11172 AAS 21254 b
17841	17841	1 year. The utility shall also earn a return on the total of
17842	17842	2 the unamortized balance of the regulatory assets, less any
17843	17843	3 deferred taxes related to the unamortized balance, at an
17844	17844	4 annual rate equal to the utility's weighted average cost
17845	17845	5 of capital that includes, based on a year-end capital
17846	17846	6 structure, the utility's actual cost of debt for the
17847	17847	7 applicable calendar year and a cost of equity, which shall
17848	17848	8 be calculated as the sum of: (I) the average for the
17849	17849	9 applicable calendar year of the monthly average yields of
17850	17850	10 30-year U.S. Treasury bonds published by the Board of
17851	17851	11 Governors of the Federal Reserve System in its weekly H.15
17852	17852	12 Statistical Release or successor publication; and (II) 580
17853	17853	13 basis points, including a revenue conversion factor
17854	17854	14 calculated to recover or refund all additional income
17855	17855	15 taxes that may be payable or receivable as a result of that
17856	17856	16 return.
17857	17857	17 (2) The utility may recover all of the costs through
17858	17858	18 an automatic adjustment clause tariff, on a volumetric
17859	17859	19 basis. The utility may file its proposed cost-recovery
17860	17860	20 tariff together with the tariff it files under subsection
17861	17861	21 (e) of this Section or at a later time. The proposed tariff
17862	17862	22 shall provide for an annual reconciliation, less any
17863	17863	23 deferred taxes related to the reconciliation, with
17864	17864	24 interest at an annual rate of return equal to the
17865	17865	25 utility's weighted average cost of capital as calculated
17866	17866	26 under paragraph (1) of this subsection (i), including a
17867	17867
17868	17868
17869	17869
17870	17870
17871	17871
17872	17872	HB3779 - 497 - LRB104 11172 AAS 21254 b
17873	17873
17874	17874
17875	17875	HB3779- 498 -LRB104 11172 AAS 21254 b HB3779 - 498 - LRB104 11172 AAS 21254 b
17876	17876	HB3779 - 498 - LRB104 11172 AAS 21254 b
17877	17877	1 revenue conversion factor calculated to recover or refund
17878	17878	2 all additional income taxes that may be payable or
17879	17879	3 receivable as a result of that return, of the revenue
17880	17880	4 requirement reflected in rates for each calendar year,
17881	17881	5 beginning with the calendar year in which the utility
17882	17882	6 files its automatic adjustment clause tariff under this
17883	17883	7 subsection (i), with what the revenue requirement would
17884	17884	8 have been had the actual cost information for the
17885	17885	9 applicable calendar year been available at the filing
17886	17886	10 date. The Commission shall review the proposed tariff and
17887	17887	11 may make changes to the tariff that are consistent with
17888	17888	12 this Section and with the Commission's authority under
17889	17889	13 Article IX of this Act, subject to notice and hearing.
17890	17890	14 Following notice and hearing, the Commission shall issue
17891	17891	15 an order approving, or approving with modification, such
17892	17892	16 tariff no later than 240 days after the utility files its
17893	17893	17 tariff.
17894	17894	18 (j) No later than 90 days after the Commission enters an
17895	17895	19 order, or order on rehearing, whichever is later, approving an
17896	17896	20 electric utility's proposed tariff under this Section, the
17897	17897	21 electric utility shall provide notice of the availability of
17898	17898	22 rebates under this Section.
17899	17899	23 (Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
17900	17900	24 (220 ILCS 5/16-107.7A new)
17901	17901	25 Sec. 16-107.7A. PJM capacity auction bill impacts.
17902	17902
17903	17903
17904	17904
17905	17905
17906	17906
17907	17907	HB3779 - 498 - LRB104 11172 AAS 21254 b
17908	17908
17909	17909
17910	17910	HB3779- 499 -LRB104 11172 AAS 21254 b HB3779 - 499 - LRB104 11172 AAS 21254 b
17911	17911	HB3779 - 499 - LRB104 11172 AAS 21254 b
17912	17912	1 (a) The recent results of PJM capacity auctions will
17913	17913	2 affect the market prices paid by customers. Load growth,
17914	17914	3 electric supply constraints, and PJM capacity auction rules
17915	17915	4 have resulted in increased PJM capacity prices for the
17916	17916	5 2025-2026 PJM delivery year, which will increase the rates
17917	17917	6 paid by customers beginning for the June 1, 2025 billing
17918	17918	7 cycle.
17919	17919	8 (b) To promote bill transparency, electric utilities
17920	17920	9 serving customers located in the PJM interconnection region
17921	17921	10 shall include at least the following statement as part of a
17922	17922	11 bill insert or bill message provided with any bill issued to
17923	17923	12 any customers for whom the electric utility provides energy
17924	17924	13 supply: "The energy charges on your bill have increased this
17925	17925	14 month due to increased capacity prices resulting from PJM
17926	17926	15 capacity auctions. These costs are not related to your
17927	17927	16 utility's delivery services".
17928	17928	17 (c) The electric utility's obligation to reflect the
17929	17929	18 information required by this subsection shall begin with the
17930	17930	19 June 1, 2025 billing cycle, and shall not continue past the
17931	17931	20 December 2025 billing period.
17932	17932	21 (220 ILCS 5/16-107.8 new)
17933	17933	22 Sec. 16-107.8. Residential time-of-use pricing.
17934	17934	23 (a) The General Assembly finds that time-of-use rates and
17935	17935	24 pricing plans can lower energy costs for consumers and reduce
17936	17936	25 grid costs as well as help the State achieve its energy policy
17937	17937
17938	17938
17939	17939
17940	17940
17941	17941
17942	17942	HB3779 - 499 - LRB104 11172 AAS 21254 b
17943	17943
17944	17944
17945	17945	HB3779- 500 -LRB104 11172 AAS 21254 b HB3779 - 500 - LRB104 11172 AAS 21254 b
17946	17946	HB3779 - 500 - LRB104 11172 AAS 21254 b
17947	17947	1 goals by improving load shape, encouraging energy
17948	17948	2 conservation, and shifting usage away from periods where
17949	17949	3 fossil fuels are used to meet peak demand. Further, by
17950	17950	4 providing consumers information relating the costs of service
17951	17951	5 to the time of energy usage, time-of-use rates can help
17952	17952	6 consumers reduce their energy bills by using electricity when
17953	17953	7 it is less costly. Time-of-use rates can help allocate
17954	17954	8 electricity system costs more accurately and thus equitably to
17955	17955	9 those who cause costs. Such rates can reduce the need for
17956	17956	10 ramping resources and increase the grid's ability to
17957	17957	11 cost-effectively integrate greater quantities of variable
17958	17958	12 renewable energy and distributed energy resources.
17959	17959	13 (b) An electric utility that has a tariff approved under
17960	17960	14 subsection (d) of Section 16-108.18 within one year of this
17961	17961	15 amendatory Act of the 104th General Assembly shall also offer
17962	17962	16 at least one market-based, residential rate for eligible
17963	17963	17 retail customers that choose to take power and energy supply
17964	17964	18 service from the utility. If the utility has a pending request
17965	17965	19 for approval of a Multi-Year Integrated Grid Plan, the utility
17966	17966	20 shall update its filing in that docket to reflect the likely
17967	17967	21 impacts of the time-of-use rate offering. The utility shall
17968	17968	22 file its time-of-use rate tariff no later than 120 days after
17969	17969	23 the effective date of this amendatory Act of the 104th General
17970	17970	24 Assembly, and each utility subject to this requirement shall
17971	17971	25 implement the requirements of this subsection by filing a
17972	17972	26 tariff with the Commission. The tariff or tariffs shall be
17973	17973
17974	17974
17975	17975
17976	17976
17977	17977
17978	17978	HB3779 - 500 - LRB104 11172 AAS 21254 b
17979	17979
17980	17980
17981	17981	HB3779- 501 -LRB104 11172 AAS 21254 b HB3779 - 501 - LRB104 11172 AAS 21254 b
17982	17982	HB3779 - 501 - LRB104 11172 AAS 21254 b
17983	17983	1 subject to the following provisions:
17984	17984	2 (1) If more than one tariff is proposed, at least one
17985	17985	3 tariff shall include at least 3 time blocks: a peak time
17986	17986	4 block, defined as 2 p.m. to 7 p.m. on nonholiday weekdays
17987	17987	5 or the 5 consecutive hours best reflecting the highest
17988	17988	6 system peak demands; an off-peak time block, defined as 10
17989	17989	7 a.m. to 2 p.m. and 7 p.m. to 10 p.m. on nonholiday weekdays
17990	17990	8 or the 7 total hours occurring in some combination before
17991	17991	9 and after the peak period, which reflect the next highest
17992	17992	10 system peak demands; and a super-off-peak time block,
17993	17993	11 defined as all other hours and including weekend days.
17994	17994	12 (2) This tariff shall strive to achieve price ratios
17995	17995	13 between the blocks as follows: the super-off-peak time
17996	17996	14 block price shall be no less than zero but no greater than
17997	17997	15 one-half of the price of the off-peak time block price,
17998	17998	16 and the off-peak time block price shall be no greater than
17999	17999	17 one-half of the price of the peak time block price.
18000	18000	18 (3) The time-of-use rate shall include the costs of
18001	18001	19 procuring power and energy pursuant to the Illinois Power
18002	18002	20 Agency procurement process that occurs under Section
18003	18003	21 16-111.5 of this Act.
18004	18004	22 (4) Adjustments to the charges set by the tariff may
18005	18005	23 be made on a semi-annual basis, as follows: each May and
18006	18006	24 November, the utility shall submit to the Commission,
18007	18007	25 through an informational filing, its updated charges, and
18008	18008	26 such charges shall take effect beginning with the June
18009	18009
18010	18010
18011	18011
18012	18012
18013	18013
18014	18014	HB3779 - 501 - LRB104 11172 AAS 21254 b
18015	18015
18016	18016
18017	18017	HB3779- 502 -LRB104 11172 AAS 21254 b HB3779 - 502 - LRB104 11172 AAS 21254 b
18018	18018	HB3779 - 502 - LRB104 11172 AAS 21254 b
18019	18019	1 monthly billing period and December monthly billing
18020	18020	2 period, respectively.
18021	18021	3 (5) The tariff shall include a purchased energy
18022	18022	4 adjustment to fully recover the supply costs for the
18023	18023	5 customers taking service under this tariff.
18024	18024	6 As used in this subsection, "eligible residential
18025	18025	7 customers" includes, but is not limited to, customers
18026	18026	8 participating in net electricity metering under the terms of
18027	18027	9 Section 16-107.5. Anything in Section 16-107.5
18028	18028	10 notwithstanding, energy credits for net-metering customers
18029	18029	11 shall be valued at the same price per kilowatt-hour as the
18030	18030	12 electric service provider would charge for kilowatt-hour
18031	18031	13 energy sales during that same hourly time-of-use period.
18032	18032	14 (c) The Commission shall, after notice and hearing,
18033	18033	15 approve the tariff or tariffs with modifications the
18034	18034	16 Commission finds necessary to improve the program design,
18035	18035	17 customer participation in the program, or coordination with
18036	18036	18 existing utility pricing programs, energy efficiency programs,
18037	18037	19 demand-response programs, and any other programs supporting
18038	18038	20 State energy policy goals and the integration of distributed
18039	18039	21 energy resources. The Commission shall also consider how the
18040	18040	22 proposed time-of-use rate design reflects the system costs and
18041	18041	23 usage patterns of the utility. A proceeding under this
18042	18042	24 subsection may not exceed 120 days in length.
18043	18043	25 (d) If the Commission issues an order pursuant to this
18044	18044	26 subsection, the affected electric utility shall contract with
18045	18045
18046	18046
18047	18047
18048	18048
18049	18049
18050	18050	HB3779 - 502 - LRB104 11172 AAS 21254 b
18051	18051
18052	18052
18053	18053	HB3779- 503 -LRB104 11172 AAS 21254 b HB3779 - 503 - LRB104 11172 AAS 21254 b
18054	18054	HB3779 - 503 - LRB104 11172 AAS 21254 b
18055	18055	1 an entity not affiliated with the electric utility to serve as
18056	18056	2 a program administrator to develop and implement a program to
18057	18057	3 provide consumer outreach, enrollment, and education
18058	18058	4 concerning time-of-use pricing and to establish and administer
18059	18059	5 an information system and technical and other customer
18060	18060	6 assistance that is necessary to enable customers to manage
18061	18061	7 electricity use. The program administrator: (i) shall be
18062	18062	8 selected and compensated by the electric utility, subject to
18063	18063	9 Commission approval; (ii) shall have demonstrated technical
18064	18064	10 and managerial competence in the development and
18065	18065	11 administration of demand management programs; and (iii) may
18066	18066	12 develop and implement risk management, energy efficiency, and
18067	18067	13 other services related to energy use management for which the
18068	18068	14 program administrator shall be compensated by participants in
18069	18069	15 the program receiving such services. The electric utility
18070	18070	16 shall provide the program administrator with all information
18071	18071	17 and assistance necessary to perform the program
18072	18072	18 administrator's duties, including, but not limited to,
18073	18073	19 customer, account, and energy use data. The electric utility
18074	18074	20 shall permit the program administrator to include inserts in
18075	18075	21 residential customer bills 2 times per year to assist with
18076	18076	22 customer outreach and enrollment. The program administrator
18077	18077	23 shall submit an annual report to the electric utility no later
18078	18078	24 than April 1 of each year describing the operation and results
18079	18079	25 of the program, including information concerning the number
18080	18080	26 and types of customers using the program, changes in
18081	18081
18082	18082
18083	18083
18084	18084
18085	18085
18086	18086	HB3779 - 503 - LRB104 11172 AAS 21254 b
18087	18087
18088	18088
18089	18089	HB3779- 504 -LRB104 11172 AAS 21254 b HB3779 - 504 - LRB104 11172 AAS 21254 b
18090	18090	HB3779 - 504 - LRB104 11172 AAS 21254 b
18091	18091	1 customers' energy use patterns, an assessment of the value of
18092	18092	2 the program to both participants and nonparticipants, and
18093	18093	3 recommendations concerning modification of the program and the
18094	18094	4 tariff or tariffs filed under this Section. This report shall
18095	18095	5 be filed by the electric utility with the Commission within 30
18096	18096	6 days after receipt and shall be available to the public on the
18097	18097	7 Commission's website.
18098	18098	8 (e) Once the tariff or tariffs has been in effect for 12
18099	18099	9 months, the Commission may, upon complaint, petition, or its
18100	18100	10 own initiative, open a proceeding to investigate whether
18101	18101	11 changes or modifications to the tariff or tariffs, program
18102	18102	12 administration and any other program design element is
18103	18103	13 necessary to achieve the goals described in subsection (a) and
18104	18104	14 to shifting usage away from periods where fossil fuels are
18105	18105	15 used to meet peak demand and realign usage to periods when
18106	18106	16 renewable generation is available. Such a proceeding may not
18107	18107	17 last more than 180 days from the date upon which the
18108	18108	18 investigation is opened by Commission order. Thereafter, the
18109	18109	19 Commission may, upon complaint, petition, or its own
18110	18110	20 initiative, open a proceeding to investigate changes or
18111	18111	21 modifications to the tariff or tariffs at any time the
18112	18112	22 Commission deems reasonable in order to achieve these
18113	18113	23 objectives.
18114	18114	24 (f) An electric utility shall be entitled to recover
18115	18115	25 reasonable costs incurred in complying with this Section, if
18116	18116	26 the recovery of the costs is fairly apportioned among its
18117	18117
18118	18118
18119	18119
18120	18120
18121	18121
18122	18122	HB3779 - 504 - LRB104 11172 AAS 21254 b
18123	18123
18124	18124
18125	18125	HB3779- 505 -LRB104 11172 AAS 21254 b HB3779 - 505 - LRB104 11172 AAS 21254 b
18126	18126	HB3779 - 505 - LRB104 11172 AAS 21254 b
18127	18127	1 residential customers.
18128	18128	2 (g) The electric utility's tariff or tariffs filed
18129	18129	3 pursuant to this Section shall be subject to the provisions of
18130	18130	4 Article IX of this Act insofar as they do not conflict with
18131	18131	5 this Section.
18132	18132	6 (h) This Section does not apply to any electric utility
18133	18133	7 providing service to 100,000 or fewer customers.
18134	18134	8 (220 ILCS 5/16-107.9 new)
18135	18135	9 Sec. 16-107.9. Virtual power plant program.
18136	18136	10 (a) As used in this Section:
18137	18137	11 "Aggregator" means a third-party entity that enrolls
18138	18138	12 customers in the program and coordinates the operation of
18139	18139	13 enrolled devices. An aggregator is a participant in the
18140	18140	14 program.
18141	18141	15 "Battery" means a behind-the-meter energy storage device
18142	18142	16 and associated equipment that operate together to fulfill
18143	18143	17 program requirements.
18144	18144	18 "Commission" means the Illinois Commerce Commission.
18145	18145	19 "Customer" means an active electric service account holder
18146	18146	20 of a utility.
18147	18147	21 "Direct participant" means a customer that enrolls in the
18148	18148	22 program directly with the utility, rather than via an
18149	18149	23 aggregator.
18150	18150	24 "Distributed energy resource" has the meaning set forth in
18151	18151	25 Section 16-107.6.
18152	18152
18153	18153
18154	18154
18155	18155
18156	18156
18157	18157	HB3779 - 505 - LRB104 11172 AAS 21254 b
18158	18158
18159	18159
18160	18160	HB3779- 506 -LRB104 11172 AAS 21254 b HB3779 - 506 - LRB104 11172 AAS 21254 b
18161	18161	HB3779 - 506 - LRB104 11172 AAS 21254 b
18162	18162	1 "Eligible device" means a customer or third party-owned
18163	18163	2 distributed energy resource that meets the requirements for
18164	18164	3 participation in the program as specified in the relevant
18165	18165	4 program rider.
18166	18166	5 "Emergency event" means an event called by the utility
18167	18167	6 with fewer than 24 hours notice.
18168	18168	7 "Enrolled customer" means a Customer that participates in
18169	18169	8 the program through either an aggregator or as a direct
18170	18170	9 participant.
18171	18171	10 "Enrolled device" means an enrolled customer's eligible
18172	18172	11 device, as specified in the relevant tariff.
18173	18173	12 "Grid event" means a grid condition for which the utility
18174	18174	13 schedules or remotely dispatches enrolled devices to respond
18175	18175	14 to, as specified in the grid service opportunities for each
18176	18176	15 tariff.
18177	18177	16 "Grid service" means a capacity, energy, or ancillary
18178	18178	17 service that supports grid operations. Such services are
18179	18179	18 "additive services" pursuant to 220 ILCS 5/16-107.6.
18180	18180	19 "Low-moderate income qualified customer" means any
18181	18181	20 resident of a Qualifying Census Tract (QCT) according to the
18182	18182	21 Department of Housing and Urban Development (HUD. In the event
18183	18183	22 the Commission cannot make reference to residents of a
18184	18184	23 Qualifying Census Tract, the Commission shall use the
18185	18185	24 definition of "low-income households" as defined in Section
18186	18186	25 1-56 of the Illinois Power Agency Act.
18187	18187	26 "Participant" means an aggregator or a direct participant.
18188	18188
18189	18189
18190	18190
18191	18191
18192	18192
18193	18193	HB3779 - 506 - LRB104 11172 AAS 21254 b
18194	18194
18195	18195
18196	18196	HB3779- 507 -LRB104 11172 AAS 21254 b HB3779 - 507 - LRB104 11172 AAS 21254 b
18197	18197	HB3779 - 507 - LRB104 11172 AAS 21254 b
18198	18198	1 "Performance payment" means a payment made to the
18199	18199	2 participant based on the performance of an enrolled device(s)
18200	18200	3 providing a grid service during a grid event.
18201	18201	4 "Performance payment rate" means the compensation rate
18202	18202	5 paid to participants for providing a particular grid service
18203	18203	6 during a grid event.
18204	18204	7 "Program Rider(s)" means one or more of the battery rider,
18205	18205	8 the non-battery rider, the electric vehicle rider, and such
18206	18206	9 other virtual power plant program riders as the Commission may
18207	18207	10 approve from time to time.
18208	18208	11 "Upfront payment" means a one-time payment made at the
18209	18209	12 time of enrollment.
18210	18210	13 "Virtual power plant" means an aggregation of
18211	18211	14 behind-the-meter distributed energy resources operated in
18212	18212	15 coordination to provide one or more grid services.
18213	18213	16 (b) The General Assembly finds that:
18214	18214	17 (1) virtual power plants are dynamic load management
18215	18215	18 and energy supply resources that can support grid
18216	18216	19 operations, reduce ratepayer costs, and achieve other
18217	18217	20 important public policy goals.
18218	18218	21 (2) Virtual power plants can reduce demand for grid
18219	18219	22 supplied electricity during peak periods, shift
18220	18220	23 electricity consumption out of peak periods, make
18221	18221	24 renewable energy generated during off-peak periods
18222	18222	25 available for use during on-peak periods, supply energy to
18223	18223	26 the grid at desired times, provide frequency regulation,
18224	18224
18225	18225
18226	18226
18227	18227
18228	18228
18229	18229	HB3779 - 507 - LRB104 11172 AAS 21254 b
18230	18230
18231	18231
18232	18232	HB3779- 508 -LRB104 11172 AAS 21254 b HB3779 - 508 - LRB104 11172 AAS 21254 b
18233	18233	HB3779 - 508 - LRB104 11172 AAS 21254 b
18234	18234	1 voltage support, and other ancillary services, improve
18235	18235	2 system resiliency and reliability, and provide other grid
18236	18236	3 services.
18237	18237	4 (3) Virtual power plants can facilitate and optimize
18238	18238	5 the utilization of electrical generation from wind and
18239	18239	6 solar energy to help utilities increase hosting capacity
18240	18240	7 and integrate more renewable energy resources.
18241	18241	8 (4) Virtual power plants can reduce costs to
18242	18242	9 ratepayers by utilizing customer-sited resources to
18243	18243	10 provide grid services, avoiding or reducing reliance on
18244	18244	11 fossil-fuel fired peaker plants, avoiding or deferring the
18245	18245	12 need to construct new and more costly grid scale
18246	18246	13 resources, optimizing the use of existing assets, and
18247	18247	14 avoiding or deferring distribution and transmission system
18248	18248	15 upgrades and other grid investments.
18249	18249	16 (5) Virtual power plants can promote equity by
18250	18250	17 reducing costs for all ratepayers, expanding access to
18251	18251	18 distributed energy resources among low- and
18252	18252	19 moderate-income customers through improved distributed
18253	18253	20 energy resource financeability, and providing other
18254	18254	21 important co-benefits, including reduction in emissions of
18255	18255	22 greenhouse gasses and other pollutants, especially in
18256	18256	23 environmental justice and other disadvantaged communities
18257	18257	24 that host fossil fuel generation plants.
18258	18258	25 (6) The United States Department of Energy estimates
18259	18259	26 that the United States could deploy 80-160 gigawatts of
18260	18260
18261	18261
18262	18262
18263	18263
18264	18264
18265	18265	HB3779 - 508 - LRB104 11172 AAS 21254 b
18266	18266
18267	18267
18268	18268	HB3779- 509 -LRB104 11172 AAS 21254 b HB3779 - 509 - LRB104 11172 AAS 21254 b
18269	18269	HB3779 - 509 - LRB104 11172 AAS 21254 b
18270	18270	1 virtual power plants by 2030 (a tripling of current
18271	18271	2 levels) to support the rapid electrification of vehicles
18272	18272	3 and homes and provide on the order of $10 billion in
18273	18273	4 ratepayer savings annually. The deployment of virtual
18274	18274	5 power plants can provide energy cost savings and other
18275	18275	6 benefits to the people of Illinois.
18276	18276	7 (7) There are significant barriers to deployment and
18277	18277	8 operation of virtual power plants, including the need for
18278	18278	9 statutory and regulatory guidance and support, greater
18279	18279	10 consistency in virtual power plant programs across
18280	18280	11 regulatory jurisdictions, and for utility commitments to
18281	18281	12 incorporate the use of virtual power plants into system
18282	18282	13 operations and long-term resource planning.
18283	18283	14 (8) It is in the public interest to advance customer
18284	18284	15 choice and leverage the expertise of private, non-utility
18285	18285	16 entities to advance innovation and implement
18286	18286	17 cost-effective clean energy solutions.
18287	18287	18 (9) The policy of Illinois shall be to maximize the
18288	18288	19 use of virtual power plants comprised of customer-owned
18289	18289	20 and third party-owned distributed energy resources to
18290	18290	21 deliver system services and other benefits through utility
18291	18291	22 administered virtual power plant programs in accordance
18292	18292	23 with the provisions of this amendatory Act of the 104th
18293	18293	24 General Assembly.
18294	18294	25 (c) Within 120 days after the effective date of this
18295	18295	26 amendatory Act of the 104th General Assembly, each electric
18296	18296
18297	18297
18298	18298
18299	18299
18300	18300
18301	18301	HB3779 - 509 - LRB104 11172 AAS 21254 b
18302	18302
18303	18303
18304	18304	HB3779- 510 -LRB104 11172 AAS 21254 b HB3779 - 510 - LRB104 11172 AAS 21254 b
18305	18305	HB3779 - 510 - LRB104 11172 AAS 21254 b
18306	18306	1 utility serving more than 300,000 customers as of January 1,
18307	18307	2 2025, shall develop and file with the Commission a virtual
18308	18308	3 power plant program proposal consistent with the provisions of
18309	18309	4 this Section. The Commission shall provide opportunities for
18310	18310	5 stakeholders to provide input on the virtual power plant
18311	18311	6 programs proposed for implementation by each utility, which
18312	18312	7 the Commission shall take into consideration in its review of
18313	18313	8 each utility's filing. Within 120 days of the utility's
18314	18314	9 filing, the Commission shall approve or modify and approve
18315	18315	10 each utility's virtual power plant program proposal for
18316	18316	11 immediate implementation by the utility.
18317	18317	12 (d) The virtual power plant program filed pursuant to
18318	18318	13 subsection (c) of this section shall be developed for
18319	18319	14 implementation through a standard offer, open access tariff
18320	18320	15 for distributed energy resources to provide system peak load
18321	18321	16 reduction and other grid services. The virtual power plant
18322	18322	17 program tariff shall:
18323	18323	18 (1) Allow for customers with battery storage,
18324	18324	19 non-battery storage and electric vehicle technologies to
18325	18325	20 enroll their respective devices in the program under
18326	18326	21 separate service riders for each technology type through
18327	18327	22 aggregators or directly with the utility. The tariff filed
18328	18328	23 pursuant to subsection (c) of this section shall at
18329	18329	24 minimum include a rider for new and existing battery
18330	18330	25 storage devices and shall incorporate additional riders
18331	18331	26 for non-battery storage devices and electric vehicles no
18332	18332
18333	18333
18334	18334
18335	18335
18336	18336
18337	18337	HB3779 - 510 - LRB104 11172 AAS 21254 b
18338	18338
18339	18339
18340	18340	HB3779- 511 -LRB104 11172 AAS 21254 b HB3779 - 511 - LRB104 11172 AAS 21254 b
18341	18341	HB3779 - 511 - LRB104 11172 AAS 21254 b
18342	18342	1 later than one year after the approval of the virtual
18343	18343	2 power plant program approved in subsection (c).
18344	18344	3 (2) Where feasible, provide a mechanism to incorporate
18345	18345	4 existing programs, such as smart thermostat demand
18346	18346	5 response or electric vehicle charging programs currently
18347	18347	6 offered by the utility, into the respective technology
18348	18348	7 riders for operation under the virtual power plant program
18349	18349	8 framework;
18350	18350	9 (3) Include grid services opportunities for each
18351	18351	10 eligible technology that customers and aggregators may
18352	18352	11 provide, which shall include, at minimum,reduction to the
18353	18353	12 utility's applicable capacity and transmission obligations
18354	18354	13 and daily wholesale energy arbitrage opportunities through
18355	18355	14 provision of grid services, and may also include:
18356	18356	15 (i) clean peak service;
18357	18357	16 (ii) local peak demand reduction;
18358	18358	17 (iii) locational value;
18359	18359	18 (iv) the avoidance or deferral of transmission
18360	18360	19 or distribution upgrades or capacity expansion;
18361	18361	20 (v) voltage support and other ancillary
18362	18362	21 services;
18363	18363	22 (vi) emergency services; and
18364	18364	23 (vii) such other functions and grid service
18365	18365	24 opportunities that the Commission determines are
18366	18366	25 supportive of efficient planning and operation of
18367	18367	26 the electrical grid.
18368	18368
18369	18369
18370	18370
18371	18371
18372	18372
18373	18373	HB3779 - 511 - LRB104 11172 AAS 21254 b
18374	18374
18375	18375
18376	18376	HB3779- 512 -LRB104 11172 AAS 21254 b HB3779 - 512 - LRB104 11172 AAS 21254 b
18377	18377	HB3779 - 512 - LRB104 11172 AAS 21254 b
18378	18378	1 (4) Provide operational parameters for each eligible
18379	18379	2 program rider and grid service, which shall include at
18380	18380	3 minimum:
18381	18381	4 (i) minimum and maximum numbers of grid events
18382	18382	5 for which the utility may dispatch the enrolled
18383	18383	6 distributed energy resources;
18384	18384	7 (ii) months of the year that grid events may
18385	18385	8 occur;
18386	18386	9 (iii) days of the week that grid events may
18387	18387	10 occur;
18388	18388	11 (iv) times of day that grid events may occur;
18389	18389	12 (v) maximum duration of grid events;
18390	18390	13 (vi) minimum day-ahead advance notification
18391	18391	14 requirement of grid events, except for emergency
18392	18392	15 events, as applicable.
18393	18393	16 (5) Include provisions for aggregators to participate
18394	18394	17 in the virtual power plant program, automatically enroll
18395	18395	18 and manage their customers' participation, receive
18396	18396	19 dispatch signals and other communications from the
18397	18397	20 utility, deliver performance measurement and verification
18398	18398	21 data to the utility, and receive virtual power plant
18399	18399	22 program payments directly from the utility;
18400	18400	23 (6) Include provisions for direct participant
18401	18401	24 customers to enroll and participate directly with the
18402	18402	25 utility, receive dispatch signals and other communications
18403	18403	26 from the utility, deliver performance measurement and
18404	18404
18405	18405
18406	18406
18407	18407
18408	18408
18409	18409	HB3779 - 512 - LRB104 11172 AAS 21254 b
18410	18410
18411	18411
18412	18412	HB3779- 513 -LRB104 11172 AAS 21254 b HB3779 - 513 - LRB104 11172 AAS 21254 b
18413	18413	HB3779 - 513 - LRB104 11172 AAS 21254 b
18414	18414	1 verification data to the utility, and receive virtual
18415	18415	2 power plant program payments directly from the utility.
18416	18416	3 Any provisions implementing this subpart that necessitate
18417	18417	4 the installation of equipment to enable direct
18418	18418	5 participation via the utility shall apply to Customers who
18419	18419	6 elect to participate as a direct participant and shall not
18420	18420	7 be required of customers who participate via an aggregator
18421	18421	8 or to customers who do not participate in the virtual
18422	18422	9 power plant program.
18423	18423	10 (7) Provide for measurement and verification of
18424	18424	11 battery performance directly at the device without the
18425	18425	12 requirement for the installation of an additional meter;
18426	18426	13 and provide such other measurement standards for
18427	18427	14 non-battery and electric vehicle technologies for approval
18428	18428	15 by the Commission.
18429	18429	16 (8) Include upfront payment and performance payment
18430	18430	17 compensation mechanisms for the battery rider system peak
18431	18431	18 reduction service. The performance payment shall be based
18432	18432	19 on the average capacity provided during grid events. The
18433	18433	20 Commission shall approve additional compensation
18434	18434	21 mechanisms as it determines appropriate for other grid
18435	18435	22 services provided under the battery, non-battery and
18436	18436	23 electric vehicle riders. The virtual power plant program
18437	18437	24 shall not assess penalties for non-performance; however,
18438	18438	25 the Commission may approve reasonable mechanisms to
18439	18439	26 disenroll customers for continued non-performance.
18440	18440
18441	18441
18442	18442
18443	18443
18444	18444
18445	18445	HB3779 - 513 - LRB104 11172 AAS 21254 b
18446	18446
18447	18447
18448	18448	HB3779- 514 -LRB104 11172 AAS 21254 b HB3779 - 514 - LRB104 11172 AAS 21254 b
18449	18449	HB3779 - 514 - LRB104 11172 AAS 21254 b
18450	18450	1 (9) Low-to-moderate income customers, and customers
18451	18451	2 located in environmental justice and other disadvantaged
18452	18452	3 communities or customer classes as the Commission may
18453	18453	4 designate shall receive a higher upfront payment in
18454	18454	5 addition to performance payments. The Commission shall
18455	18455	6 coordinate with state energy officials and departments to
18456	18456	7 make funding from the federal Inflation Reduction Act and
18457	18457	8 such other sources as may be available for use in
18458	18458	9 providing higher upfront payments to customers classes as
18459	18459	10 may be approved by the Commission in accordance with this
18460	18460	11 subsection.
18461	18461	12 (10) The Commission shall determine the value of grid
18462	18462	13 service opportunities based on the National Standards
18463	18463	14 Practice Manual for Benefit Cost Analysis of Distributed
18464	18464	15 Energy Resources. The Commission shall take this value
18465	18465	16 into account when establishing the upfront payment and
18466	18466	17 performance payment under subsection (8) of this section.
18467	18467	18 (11) Allow participants to lock in the performance
18468	18468	19 payment rate applicable at the time of enrollment for a
18469	18469	20 minimum of five years, after which time the participant
18470	18470	21 may reenroll at the then applicable performance payment
18471	18471	22 rate for an additional five-year term;
18472	18472	23 (12) in addition to the compensation for each grid
18473	18473	24 service, the tariff shall provide that energy exported
18474	18474	25 from a participating distributed energy resource shall be
18475	18475	26 credited to the enrolled customer at a value equal to the
18476	18476
18477	18477
18478	18478
18479	18479
18480	18480
18481	18481	HB3779 - 514 - LRB104 11172 AAS 21254 b
18482	18482
18483	18483
18484	18484	HB3779- 515 -LRB104 11172 AAS 21254 b HB3779 - 515 - LRB104 11172 AAS 21254 b
18485	18485	HB3779 - 515 - LRB104 11172 AAS 21254 b
18486	18486	1 retail rate charged by the utility for energy at the time
18487	18487	2 of the export, irrespective of the export compensation
18488	18488	3 rate specified in the customer's underlying
18489	18489	4 interconnection tariff. Nothing in this section shall
18490	18490	5 affect the rate of compensation for energy that is
18491	18491	6 exported outside of a grid event under a
18492	18492	7 Commission-approved virtual power plant program.
18493	18493	8 (13) Enrolled customers may co-participate in any
18494	18494	9 applicable underlying interconnection tariff and may
18495	18495	10 provide multiple grid services and/or co-participate in
18496	18496	11 other riders under the virtual power plant program, or
18497	18497	12 other grid service programs outside the virtual power
18498	18498	13 plant program, including wholesale market programs, except
18499	18499	14 as otherwise provided by the Commission. Enrolled
18500	18500	15 customers shall remain eligible to receive state and
18501	18501	16 federal incentives in addition to any compensation
18502	18502	17 received for participating in the virtual power plant
18503	18503	18 program. Crediting for exported energy shall not
18504	18504	19 constitute double counting.
18505	18505	20 (14) The Commission may adopt other reasonable
18506	18506	21 requirements for participation consistent with this
18507	18507	22 subsection; provided that collateral from a direct
18508	18508	23 participant or an aggregator shall not be required for
18509	18509	24 participation.
18510	18510	25 (e) Utility-owned resources shall not be eligible to
18511	18511	26 participate in the virtual power plant program. Utilities and
18512	18512
18513	18513
18514	18514
18515	18515
18516	18516
18517	18517	HB3779 - 515 - LRB104 11172 AAS 21254 b
18518	18518
18519	18519
18520	18520	HB3779- 516 -LRB104 11172 AAS 21254 b HB3779 - 516 - LRB104 11172 AAS 21254 b
18521	18521	HB3779 - 516 - LRB104 11172 AAS 21254 b
18522	18522	1 utility affiliates may not be aggregators. Except that
18523	18523	2 utilities may develop bundled supply, delivery, and virtual
18524	18524	3 power plant rates that incentivize grid beneficial behavior
18525	18525	4 that captures grid opportunities.
18526	18526	5 (f) The utility may contract with a third party
18527	18527	6 distributed energy resource management system provider to
18528	18528	7 assist with program implementation provided that
18529	18529	8 implementation shall not be delayed due to the lack of
18530	18530	9 utility-owned distributed energy resource management system
18531	18531	10 capabilities or third party distributed energy resource
18532	18532	11 management system capabilities.
18533	18533	12 (g) Utilities may seek to recover prudently incurred costs
18534	18534	13 to facilitate the virtual power plant program approved
18535	18535	14 pursuant to subsection (c), including but not limited to:
18536	18536	15 distributed energy resource management system provider and
18537	18537	16 other service contract costs, operations and maintenance
18538	18538	17 expenses, information technology costs, and such other costs,
18539	18539	18 expenses and investments the Commission finds necessary and
18540	18540	19 prudent for the development and implementation of the program.
18541	18541	20 (h) The provisions of subsection (g) of this Section
18542	18542	21 notwithstanding, the utility shall recover the cost of virtual
18543	18543	22 power plant program upfront payments and performance payments
18544	18544	23 and such other payments made to participants through cost
18545	18545	24 recovery mechanisms approved by the Commission. The Commission
18546	18546	25 may at its discretion allow a reasonable rate of return on the
18547	18547	26 cost of payments made for the provision of grid services and
18548	18548
18549	18549
18550	18550
18551	18551
18552	18552
18553	18553	HB3779 - 516 - LRB104 11172 AAS 21254 b
18554	18554
18555	18555
18556	18556	HB3779- 517 -LRB104 11172 AAS 21254 b HB3779 - 517 - LRB104 11172 AAS 21254 b
18557	18557	HB3779 - 517 - LRB104 11172 AAS 21254 b
18558	18558	1 such other costs approved by the Commission and shall take any
18559	18559	2 such allowance into consideration when considering performance
18560	18560	3 incentives pursuant to subsection (j).
18561	18561	4 (i) The Commission shall initiate a proceeding to develop
18562	18562	5 capacity procurement targets applicable to the utility for the
18563	18563	6 utilization of the virtual power plant program with
18564	18564	7 corresponding performance incentives for achieving the
18565	18565	8 established targets in accordance with the provisions of this
18566	18566	9 section.
18567	18567	10 (j) Within 270 days of the effective date of this Act the
18568	18568	11 Commission shall, at minimum:
18569	18569	12 (1) establish annual capacity procurement and
18570	18570	13 performance targets for the system peak reduction service,
18571	18571	14 which shall be designed to meaningfully increase
18572	18572	15 year-over-year the amount of capacity procured for system
18573	18573	16 peak reduction over a five year period. The Commission
18574	18574	17 shall establish corresponding performance incentives for
18575	18575	18 achieving the target established for each year of the
18576	18576	19 performance period.
18577	18577	20 (2) the performance incentives established pursuant to
18578	18578	21 paragraph (1) of this subsection shall include financial
18579	18579	22 rewards for achieving the targets and may include
18580	18580	23 financial penalties for failure to achieve the targets.
18581	18581	24 (3) the Commission shall establish new targets for
18582	18582	25 subsequent 5-year periods.
18583	18583	26 (4) the performance targets and incentives established
18584	18584
18585	18585
18586	18586
18587	18587
18588	18588
18589	18589	HB3779 - 517 - LRB104 11172 AAS 21254 b
18590	18590
18591	18591
18592	18592	HB3779- 518 -LRB104 11172 AAS 21254 b HB3779 - 518 - LRB104 11172 AAS 21254 b
18593	18593	HB3779 - 518 - LRB104 11172 AAS 21254 b
18594	18594	1 pursuant to this section shall take effect no later than
18595	18595	2 the beginning of the second calendar year following the
18596	18596	3 year in which the Commission approves a utility's virtual
18597	18597	4 power plant program pursuant to subsection (c) of this
18598	18598	5 Section.
18599	18599	6 (k) The Commission shall develop targets and performance
18600	18600	7 incentives for additional grid services adopted pursuant to
18601	18601	8 subsection (d) of this Section no later than 270 days after
18602	18602	9 such additional grid services are approved for implementation
18603	18603	10 through the tariff, which shall take effect no later than the
18604	18604	11 beginning of the second calendar year following the year in
18605	18605	12 which the Commission approves such additional grid services.
18606	18606	13 (l) Each utility shall file an annual report no later than
18607	18607	14 January 31 of each year that shall include, at minimum: the
18608	18608	15 total capacity enrolled in each program rider developed
18609	18609	16 pursuant to the requirements of Section, broken out by
18610	18610	17 technology type, customer class, and aggregator and direct
18611	18611	18 participant status for each grid service opportunity offered
18612	18612	19 in the prior calendar year along with recommendations to
18613	18613	20 increase participation in the virtual power plant program, and
18614	18614	21 such other information as the Commission may require from time
18615	18615	22 to time.
18616	18616	23 (m) Each utility shall amend existing tariffs and
18617	18617	24 procedures that limit customers' ability to participate in
18618	18618	25 providing grid services under this program such as limitations
18619	18619	26 on charging energy storage devices with grid energy or
18620	18620
18621	18621
18622	18622
18623	18623
18624	18624
18625	18625	HB3779 - 518 - LRB104 11172 AAS 21254 b
18626	18626
18627	18627
18628	18628	HB3779- 519 -LRB104 11172 AAS 21254 b HB3779 - 519 - LRB104 11172 AAS 21254 b
18629	18629	HB3779 - 519 - LRB104 11172 AAS 21254 b
18630	18630	1 exporting energy to the grid from battery discharge.
18631	18631	2 (220 ILCS 5/16-108)
18632	18632	3 Sec. 16-108. Recovery of costs associated with the
18633	18633	4 provision of delivery and other services.
18634	18634	5 (a) An electric utility shall file a delivery services
18635	18635	6 tariff with the Commission at least 210 days prior to the date
18636	18636	7 that it is required to begin offering such services pursuant
18637	18637	8 to this Act. An electric utility shall provide the components
18638	18638	9 of delivery services that are subject to the jurisdiction of
18639	18639	10 the Federal Energy Regulatory Commission at the same prices,
18640	18640	11 terms and conditions set forth in its applicable tariff as
18641	18641	12 approved or allowed into effect by that Commission. The
18642	18642	13 Commission shall otherwise have the authority pursuant to
18643	18643	14 Article IX to review, approve, and modify the prices, terms
18644	18644	15 and conditions of those components of delivery services not
18645	18645	16 subject to the jurisdiction of the Federal Energy Regulatory
18646	18646	17 Commission, including the authority to determine the extent to
18647	18647	18 which such delivery services should be offered on an unbundled
18648	18648	19 basis. In making any such determination the Commission shall
18649	18649	20 consider, at a minimum, the effect of additional unbundling on
18650	18650	21 (i) the objective of just and reasonable rates, (ii) electric
18651	18651	22 utility employees, and (iii) the development of competitive
18652	18652	23 markets for electric energy services in Illinois.
18653	18653	24 (b) The Commission shall enter an order approving, or
18654	18654	25 approving as modified, the delivery services tariff no later
18655	18655
18656	18656
18657	18657
18658	18658
18659	18659
18660	18660	HB3779 - 519 - LRB104 11172 AAS 21254 b
18661	18661
18662	18662
18663	18663	HB3779- 520 -LRB104 11172 AAS 21254 b HB3779 - 520 - LRB104 11172 AAS 21254 b
18664	18664	HB3779 - 520 - LRB104 11172 AAS 21254 b
18665	18665	1 than 30 days prior to the date on which the electric utility
18666	18666	2 must commence offering such services. The Commission may
18667	18667	3 subsequently modify such tariff pursuant to this Act.
18668	18668	4 (c) The electric utility's tariffs shall define the
18669	18669	5 classes of its customers for purposes of delivery services
18670	18670	6 charges. Delivery services shall be priced and made available
18671	18671	7 to all retail customers electing delivery services in each
18672	18672	8 such class on a nondiscriminatory basis regardless of whether
18673	18673	9 the retail customer chooses the electric utility, an affiliate
18674	18674	10 of the electric utility, or another entity as its supplier of
18675	18675	11 electric power and energy. Charges for delivery services shall
18676	18676	12 be cost based, and shall allow the electric utility to recover
18677	18677	13 the costs of providing delivery services through its charges
18678	18678	14 to its delivery service customers that use the facilities and
18679	18679	15 services associated with such costs. Such costs shall include
18680	18680	16 the costs of owning, operating and maintaining transmission
18681	18681	17 and distribution facilities. The Commission shall also be
18682	18682	18 authorized to consider whether, and if so to what extent, the
18683	18683	19 following costs are appropriately included in the electric
18684	18684	20 utility's delivery services rates: (i) the costs of that
18685	18685	21 portion of generation facilities used for the production and
18686	18686	22 absorption of reactive power in order that retail customers
18687	18687	23 located in the electric utility's service area can receive
18688	18688	24 electric power and energy from suppliers other than the
18689	18689	25 electric utility, and (ii) the costs associated with the use
18690	18690	26 and redispatch of generation facilities to mitigate
18691	18691
18692	18692
18693	18693
18694	18694
18695	18695
18696	18696	HB3779 - 520 - LRB104 11172 AAS 21254 b
18697	18697
18698	18698
18699	18699	HB3779- 521 -LRB104 11172 AAS 21254 b HB3779 - 521 - LRB104 11172 AAS 21254 b
18700	18700	HB3779 - 521 - LRB104 11172 AAS 21254 b
18701	18701	1 constraints on the transmission or distribution system in
18702	18702	2 order that retail customers located in the electric utility's
18703	18703	3 service area can receive electric power and energy from
18704	18704	4 suppliers other than the electric utility. Nothing in this
18705	18705	5 subsection shall be construed as directing the Commission to
18706	18706	6 allocate any of the costs described in (i) or (ii) that are
18707	18707	7 found to be appropriately included in the electric utility's
18708	18708	8 delivery services rates to any particular customer group or
18709	18709	9 geographic area in setting delivery services rates.
18710	18710	10 (d) The Commission shall establish charges, terms and
18711	18711	11 conditions for delivery services that are just and reasonable
18712	18712	12 and shall take into account customer impacts when establishing
18713	18713	13 such charges. In establishing charges, terms and conditions
18714	18714	14 for delivery services, the Commission shall take into account
18715	18715	15 voltage level differences. A retail customer shall have the
18716	18716	16 option to request to purchase electric service at any delivery
18717	18717	17 service voltage reasonably and technically feasible from the
18718	18718	18 electric facilities serving that customer's premises provided
18719	18719	19 that there are no significant adverse impacts upon system
18720	18720	20 reliability or system efficiency. A retail customer shall also
18721	18721	21 have the option to request to purchase electric service at any
18722	18722	22 point of delivery that is reasonably and technically feasible
18723	18723	23 provided that there are no significant adverse impacts on
18724	18724	24 system reliability or efficiency. Such requests shall not be
18725	18725	25 unreasonably denied.
18726	18726	26 (e) Electric utilities shall recover the costs of
18727	18727
18728	18728
18729	18729
18730	18730
18731	18731
18732	18732	HB3779 - 521 - LRB104 11172 AAS 21254 b
18733	18733
18734	18734
18735	18735	HB3779- 522 -LRB104 11172 AAS 21254 b HB3779 - 522 - LRB104 11172 AAS 21254 b
18736	18736	HB3779 - 522 - LRB104 11172 AAS 21254 b
18737	18737	1 installing, operating or maintaining facilities for the
18738	18738	2 particular benefit of one or more delivery services customers,
18739	18739	3 including without limitation any costs incurred in complying
18740	18740	4 with a customer's request to be served at a different voltage
18741	18741	5 level, directly from the retail customer or customers for
18742	18742	6 whose benefit the costs were incurred, to the extent such
18743	18743	7 costs are not recovered through the charges referred to in
18744	18744	8 subsections (c) and (d) of this Section.
18745	18745	9 (f) An electric utility shall be entitled but not required
18746	18746	10 to implement transition charges in conjunction with the
18747	18747	11 offering of delivery services pursuant to Section 16-104. If
18748	18748	12 an electric utility implements transition charges, it shall
18749	18749	13 implement such charges for all delivery services customers and
18750	18750	14 for all customers described in subsection (h), but shall not
18751	18751	15 implement transition charges for power and energy that a
18752	18752	16 retail customer takes from cogeneration or self-generation
18753	18753	17 facilities located on that retail customer's premises, if such
18754	18754	18 facilities meet the following criteria:
18755	18755	19 (i) the cogeneration or self-generation facilities
18756	18756	20 serve a single retail customer and are located on that
18757	18757	21 retail customer's premises (for purposes of this
18758	18758	22 subparagraph and subparagraph (ii), an industrial or
18759	18759	23 manufacturing retail customer and a third party contractor
18760	18760	24 that is served by such industrial or manufacturing
18761	18761	25 customer through such retail customer's own electrical
18762	18762	26 distribution facilities under the circumstances described
18763	18763
18764	18764
18765	18765
18766	18766
18767	18767
18768	18768	HB3779 - 522 - LRB104 11172 AAS 21254 b
18769	18769
18770	18770
18771	18771	HB3779- 523 -LRB104 11172 AAS 21254 b HB3779 - 523 - LRB104 11172 AAS 21254 b
18772	18772	HB3779 - 523 - LRB104 11172 AAS 21254 b
18773	18773	1 in subsection (vi) of the definition of "alternative
18774	18774	2 retail electric supplier" set forth in Section 16-102,
18775	18775	3 shall be considered a single retail customer);
18776	18776	4 (ii) the cogeneration or self-generation facilities
18777	18777	5 either (A) are sized pursuant to generally accepted
18778	18778	6 engineering standards for the retail customer's electrical
18779	18779	7 load at that premises (taking into account standby or
18780	18780	8 other reliability considerations related to that retail
18781	18781	9 customer's operations at that site) or (B) if the facility
18782	18782	10 is a cogeneration facility located on the retail
18783	18783	11 customer's premises, the retail customer is the thermal
18784	18784	12 host for that facility and the facility has been designed
18785	18785	13 to meet that retail customer's thermal energy requirements
18786	18786	14 resulting in electrical output beyond that retail
18787	18787	15 customer's electrical demand at that premises, comply with
18788	18788	16 the operating and efficiency standards applicable to
18789	18789	17 "qualifying facilities" specified in title 18 Code of
18790	18790	18 Federal Regulations Section 292.205 as in effect on the
18791	18791	19 effective date of this amendatory Act of 1999;
18792	18792	20 (iii) the retail customer on whose premises the
18793	18793	21 facilities are located either has an exclusive right to
18794	18794	22 receive, and corresponding obligation to pay for, all of
18795	18795	23 the electrical capacity of the facility, or in the case of
18796	18796	24 a cogeneration facility that has been designed to meet the
18797	18797	25 retail customer's thermal energy requirements at that
18798	18798	26 premises, an identified amount of the electrical capacity
18799	18799
18800	18800
18801	18801
18802	18802
18803	18803
18804	18804	HB3779 - 523 - LRB104 11172 AAS 21254 b
18805	18805
18806	18806
18807	18807	HB3779- 524 -LRB104 11172 AAS 21254 b HB3779 - 524 - LRB104 11172 AAS 21254 b
18808	18808	HB3779 - 524 - LRB104 11172 AAS 21254 b
18809	18809	1 of the facility, over a minimum 5-year period; and
18810	18810	2 (iv) if the cogeneration facility is sized for the
18811	18811	3 retail customer's thermal load at that premises but
18812	18812	4 exceeds the electrical load, any sales of excess power or
18813	18813	5 energy are made only at wholesale, are subject to the
18814	18814	6 jurisdiction of the Federal Energy Regulatory Commission,
18815	18815	7 and are not for the purpose of circumventing the
18816	18816	8 provisions of this subsection (f).
18817	18817	9 If a generation facility located at a retail customer's
18818	18818	10 premises does not meet the above criteria, an electric utility
18819	18819	11 implementing transition charges shall implement a transition
18820	18820	12 charge until December 31, 2006 for any power and energy taken
18821	18821	13 by such retail customer from such facility as if such power and
18822	18822	14 energy had been delivered by the electric utility. Provided,
18823	18823	15 however, that an industrial retail customer that is taking
18824	18824	16 power from a generation facility that does not meet the above
18825	18825	17 criteria but that is located on such customer's premises will
18826	18826	18 not be subject to a transition charge for the power and energy
18827	18827	19 taken by such retail customer from such generation facility if
18828	18828	20 the facility does not serve any other retail customer and
18829	18829	21 either was installed on behalf of the customer and for its own
18830	18830	22 use prior to January 1, 1997, or is both predominantly fueled
18831	18831	23 by byproducts of such customer's manufacturing process at such
18832	18832	24 premises and sells or offers an average of 300 megawatts or
18833	18833	25 more of electricity produced from such generation facility
18834	18834	26 into the wholesale market. Such charges shall be calculated as
18835	18835
18836	18836
18837	18837
18838	18838
18839	18839
18840	18840	HB3779 - 524 - LRB104 11172 AAS 21254 b
18841	18841
18842	18842
18843	18843	HB3779- 525 -LRB104 11172 AAS 21254 b HB3779 - 525 - LRB104 11172 AAS 21254 b
18844	18844	HB3779 - 525 - LRB104 11172 AAS 21254 b
18845	18845	1 provided in Section 16-102, and shall be collected on each
18846	18846	2 kilowatt-hour delivered under a delivery services tariff to a
18847	18847	3 retail customer from the date the customer first takes
18848	18848	4 delivery services until December 31, 2006 except as provided
18849	18849	5 in subsection (h) of this Section. Provided, however, that an
18850	18850	6 electric utility, other than an electric utility providing
18851	18851	7 service to at least 1,000,000 customers in this State on
18852	18852	8 January 1, 1999, shall be entitled to petition for entry of an
18853	18853	9 order by the Commission authorizing the electric utility to
18854	18854	10 implement transition charges for an additional period ending
18855	18855	11 no later than December 31, 2008. The electric utility shall
18856	18856	12 file its petition with supporting evidence no earlier than 16
18857	18857	13 months, and no later than 12 months, prior to December 31,
18858	18858	14 2006. The Commission shall hold a hearing on the electric
18859	18859	15 utility's petition and shall enter its order no later than 8
18860	18860	16 months after the petition is filed. The Commission shall
18861	18861	17 determine whether and to what extent the electric utility
18862	18862	18 shall be authorized to implement transition charges for an
18863	18863	19 additional period. The Commission may authorize the electric
18864	18864	20 utility to implement transition charges for some or all of the
18865	18865	21 additional period, and shall determine the mitigation factors
18866	18866	22 to be used in implementing such transition charges; provided,
18867	18867	23 that the Commission shall not authorize mitigation factors
18868	18868	24 less than 110% of those in effect during the 12 months ended
18869	18869	25 December 31, 2006. In making its determination, the Commission
18870	18870	26 shall consider the following factors: the necessity to
18871	18871
18872	18872
18873	18873
18874	18874
18875	18875
18876	18876	HB3779 - 525 - LRB104 11172 AAS 21254 b
18877	18877
18878	18878
18879	18879	HB3779- 526 -LRB104 11172 AAS 21254 b HB3779 - 526 - LRB104 11172 AAS 21254 b
18880	18880	HB3779 - 526 - LRB104 11172 AAS 21254 b
18881	18881	1 implement transition charges for an additional period in order
18882	18882	2 to maintain the financial integrity of the electric utility;
18883	18883	3 the prudence of the electric utility's actions in reducing its
18884	18884	4 costs since the effective date of this amendatory Act of 1997;
18885	18885	5 the ability of the electric utility to provide safe, adequate
18886	18886	6 and reliable service to retail customers in its service area;
18887	18887	7 and the impact on competition of allowing the electric utility
18888	18888	8 to implement transition charges for the additional period.
18889	18889	9 (g) The electric utility shall file tariffs that establish
18890	18890	10 the transition charges to be paid by each class of customers to
18891	18891	11 the electric utility in conjunction with the provision of
18892	18892	12 delivery services. The electric utility's tariffs shall define
18893	18893	13 the classes of its customers for purposes of calculating
18894	18894	14 transition charges. The electric utility's tariffs shall
18895	18895	15 provide for the calculation of transition charges on a
18896	18896	16 customer-specific basis for any retail customer whose average
18897	18897	17 monthly maximum electrical demand on the electric utility's
18898	18898	18 system during the 6 months with the customer's highest monthly
18899	18899	19 maximum electrical demands equals or exceeds 3.0 megawatts for
18900	18900	20 electric utilities having more than 1,000,000 customers, and
18901	18901	21 for other electric utilities for any customer that has an
18902	18902	22 average monthly maximum electrical demand on the electric
18903	18903	23 utility's system of one megawatt or more, and (A) for which
18904	18904	24 there exists data on the customer's usage during the 3 years
18905	18905	25 preceding the date that the customer became eligible to take
18906	18906	26 delivery services, or (B) for which there does not exist data
18907	18907
18908	18908
18909	18909
18910	18910
18911	18911
18912	18912	HB3779 - 526 - LRB104 11172 AAS 21254 b
18913	18913
18914	18914
18915	18915	HB3779- 527 -LRB104 11172 AAS 21254 b HB3779 - 527 - LRB104 11172 AAS 21254 b
18916	18916	HB3779 - 527 - LRB104 11172 AAS 21254 b
18917	18917	1 on the customer's usage during the 3 years preceding the date
18918	18918	2 that the customer became eligible to take delivery services,
18919	18919	3 if in the electric utility's reasonable judgment there exists
18920	18920	4 comparable usage information or a sufficient basis to develop
18921	18921	5 such information, and further provided that the electric
18922	18922	6 utility can require customers for which an individual
18923	18923	7 calculation is made to sign contracts that set forth the
18924	18924	8 transition charges to be paid by the customer to the electric
18925	18925	9 utility pursuant to the tariff.
18926	18926	10 (h) An electric utility shall also be entitled to file
18927	18927	11 tariffs that allow it to collect transition charges from
18928	18928	12 retail customers in the electric utility's service area that
18929	18929	13 do not take delivery services but that take electric power or
18930	18930	14 energy from an alternative retail electric supplier or from an
18931	18931	15 electric utility other than the electric utility in whose
18932	18932	16 service area the customer is located. Such charges shall be
18933	18933	17 calculated, in accordance with the definition of transition
18934	18934	18 charges in Section 16-102, for the period of time that the
18935	18935	19 customer would be obligated to pay transition charges if it
18936	18936	20 were taking delivery services, except that no deduction for
18937	18937	21 delivery services revenues shall be made in such calculation,
18938	18938	22 and usage data from the customer's class shall be used where
18939	18939	23 historical usage data is not available for the individual
18940	18940	24 customer. The customer shall be obligated to pay such charges
18941	18941	25 on a lump sum basis on or before the date on which the customer
18942	18942	26 commences to take service from the alternative retail electric
18943	18943
18944	18944
18945	18945
18946	18946
18947	18947
18948	18948	HB3779 - 527 - LRB104 11172 AAS 21254 b
18949	18949
18950	18950
18951	18951	HB3779- 528 -LRB104 11172 AAS 21254 b HB3779 - 528 - LRB104 11172 AAS 21254 b
18952	18952	HB3779 - 528 - LRB104 11172 AAS 21254 b
18953	18953	1 supplier or other electric utility, provided, that the
18954	18954	2 electric utility in whose service area the customer is located
18955	18955	3 shall offer the customer the option of signing a contract
18956	18956	4 pursuant to which the customer pays such charges ratably over
18957	18957	5 the period in which the charges would otherwise have applied.
18958	18958	6 (i) An electric utility shall be entitled to add to the
18959	18959	7 bills of delivery services customers charges pursuant to
18960	18960	8 Sections 9-221, 9-222 (except as provided in Section 9-222.1),
18961	18961	9 and Section 16-114 of this Act, Section 5-5 of the Electricity
18962	18962	10 Infrastructure Maintenance Fee Law, Section 6-5 of the
18963	18963	11 Renewable Energy, Energy Efficiency, and Coal Resources
18964	18964	12 Development Law of 1997, and Section 13 of the Energy
18965	18965	13 Assistance Act.
18966	18966	14 (i-5) An electric utility required to impose the Coal to
18967	18967	15 Solar and Energy Storage Initiative Charge provided for in
18968	18968	16 subsection (c-5) of Section 1-75 of the Illinois Power Agency
18969	18969	17 Act shall add such charge to the bills of its delivery services
18970	18970	18 customers pursuant to the terms of a tariff conforming to the
18971	18971	19 requirements of subsection (c-5) of Section 1-75 of the
18972	18972	20 Illinois Power Agency Act and this subsection (i-5) and filed
18973	18973	21 with and approved by the Commission. The electric utility
18974	18974	22 shall file its proposed tariff with the Commission on or
18975	18975	23 before July 1, 2022 to be effective, after review and approval
18976	18976	24 or modification by the Commission, beginning January 1, 2023.
18977	18977	25 On or before December 1, 2022, the Commission shall review the
18978	18978	26 electric utility's proposed tariff, including by conducting a
18979	18979
18980	18980
18981	18981
18982	18982
18983	18983
18984	18984	HB3779 - 528 - LRB104 11172 AAS 21254 b
18985	18985
18986	18986
18987	18987	HB3779- 529 -LRB104 11172 AAS 21254 b HB3779 - 529 - LRB104 11172 AAS 21254 b
18988	18988	HB3779 - 529 - LRB104 11172 AAS 21254 b
18989	18989	1 docketed proceeding if deemed necessary by the Commission, and
18990	18990	2 shall approve the proposed tariff or direct the electric
18991	18991	3 utility to make modifications the Commission finds necessary
18992	18992	4 for the tariff to conform to the requirements of subsection
18993	18993	5 (c-5) of Section 1-75 of the Illinois Power Agency Act and this
18994	18994	6 subsection (i-5). The electric utility's tariff shall provide
18995	18995	7 for imposition of the Coal to Solar and Energy Storage
18996	18996	8 Initiative Charge on a per-kilowatthour basis to all
18997	18997	9 kilowatthours delivered by the electric utility to its
18998	18998	10 delivery services customers. The tariff shall provide for the
18999	18999	11 calculation of the Coal to Solar and Energy Storage Initiative
19000	19000	12 Charge to be in effect for the year beginning January 1, 2023
19001	19001	13 and each year beginning January 1 thereafter, sufficient to
19002	19002	14 collect the electric utility's estimated payment obligations
19003	19003	15 for the delivery year beginning the following June 1 under
19004	19004	16 contracts for purchase of renewable energy credits entered
19005	19005	17 into pursuant to subsection (c-5) of Section 1-75 of the
19006	19006	18 Illinois Power Agency Act and the obligations of the
19007	19007	19 Department of Commerce and Economic Opportunity, or any
19008	19008	20 successor department or agency, which for purposes of this
19009	19009	21 subsection (i-5) shall be referred to as the Department, to
19010	19010	22 make grant payments during such delivery year from the Coal to
19011	19011	23 Solar and Energy Storage Initiative Fund pursuant to grant
19012	19012	24 contracts entered into pursuant to subsection (c-5) of Section
19013	19013	25 1-75 of the Illinois Power Agency Act, and using the electric
19014	19014	26 utility's kilowatthour deliveries to its delivery services
19015	19015
19016	19016
19017	19017
19018	19018
19019	19019
19020	19020	HB3779 - 529 - LRB104 11172 AAS 21254 b
19021	19021
19022	19022
19023	19023	HB3779- 530 -LRB104 11172 AAS 21254 b HB3779 - 530 - LRB104 11172 AAS 21254 b
19024	19024	HB3779 - 530 - LRB104 11172 AAS 21254 b
19025	19025	1 customers during the delivery year ended May 31 of the
19026	19026	2 preceding calendar year. On or before November 1 of each year
19027	19027	3 beginning November 1, 2022, the Department shall notify the
19028	19028	4 electric utilities of the amount of the Department's estimated
19029	19029	5 obligations for grant payments during the delivery year
19030	19030	6 beginning the following June 1 pursuant to grant contracts
19031	19031	7 entered into pursuant to subsection (c-5) of Section 1-75 of
19032	19032	8 the Illinois Power Agency Act; and each electric utility shall
19033	19033	9 incorporate in the calculation of its Coal to Solar and Energy
19034	19034	10 Storage Initiative Charge the fractional portion of the
19035	19035	11 Department's estimated obligations equal to the electric
19036	19036	12 utility's kilowatthour deliveries to its delivery services
19037	19037	13 customers in the delivery year ended the preceding May 31
19038	19038	14 divided by the aggregate deliveries of both electric utilities
19039	19039	15 to delivery services customers in such delivery year. The
19040	19040	16 electric utility shall remit on a monthly basis to the State
19041	19041	17 Treasurer, for deposit in the Coal to Solar and Energy Storage
19042	19042	18 Initiative Fund provided for in subsection (c-5) of Section
19043	19043	19 1-75 of the Illinois Power Agency Act, the electric utility's
19044	19044	20 collections of the Coal to Solar and Energy Storage Initiative
19045	19045	21 Charge estimated to be needed by the Department for grant
19046	19046	22 payments pursuant to grant contracts entered into pursuant to
19047	19047	23 subsection (c-5) of Section 1-75 of the Illinois Power Agency
19048	19048	24 Act. The initial charge under the electric utility's tariff
19049	19049	25 shall be effective for kilowatthours delivered beginning
19050	19050	26 January 1, 2023, and thereafter shall be revised to be
19051	19051
19052	19052
19053	19053
19054	19054
19055	19055
19056	19056	HB3779 - 530 - LRB104 11172 AAS 21254 b
19057	19057
19058	19058
19059	19059	HB3779- 531 -LRB104 11172 AAS 21254 b HB3779 - 531 - LRB104 11172 AAS 21254 b
19060	19060	HB3779 - 531 - LRB104 11172 AAS 21254 b
19061	19061	1 effective January 1, 2024 and each January 1 thereafter, based
19062	19062	2 on the payment obligations for the delivery year beginning the
19063	19063	3 following June 1. The tariff shall provide for the electric
19064	19064	4 utility to make an annual filing with the Commission on or
19065	19065	5 before November 15 of each year, beginning in 2023, setting
19066	19066	6 forth the Coal to Solar and Energy Storage Initiative Charge
19067	19067	7 to be in effect for the year beginning the following January 1.
19068	19068	8 The electric utility's tariff shall also provide that the
19069	19069	9 electric utility shall make a filing with the Commission on or
19070	19070	10 before August 1 of each year beginning in 2024 setting forth a
19071	19071	11 reconciliation, for the delivery year ended the preceding May
19072	19072	12 31, of the electric utility's collections of the Coal to Solar
19073	19073	13 and Energy Storage Initiative Charge against actual payments
19074	19074	14 for renewable energy credits pursuant to contracts entered
19075	19075	15 into, and the actual grant payments by the Department pursuant
19076	19076	16 to grant contracts entered into, pursuant to subsection (c-5)
19077	19077	17 of Section 1-75 of the Illinois Power Agency Act. The tariff
19078	19078	18 shall provide that any excess or shortfall of collections to
19079	19079	19 payments shall be deducted from or added to, on a
19080	19080	20 per-kilowatthour basis, the Coal to Solar and Energy Storage
19081	19081	21 Initiative Charge, over the 6-month period beginning October 1
19082	19082	22 of that calendar year.
19083	19083	23 (j) If a retail customer that obtains electric power and
19084	19084	24 energy from cogeneration or self-generation facilities
19085	19085	25 installed for its own use on or before January 1, 1997,
19086	19086	26 subsequently takes service from an alternative retail electric
19087	19087
19088	19088
19089	19089
19090	19090
19091	19091
19092	19092	HB3779 - 531 - LRB104 11172 AAS 21254 b
19093	19093
19094	19094
19095	19095	HB3779- 532 -LRB104 11172 AAS 21254 b HB3779 - 532 - LRB104 11172 AAS 21254 b
19096	19096	HB3779 - 532 - LRB104 11172 AAS 21254 b
19097	19097	1 supplier or an electric utility other than the electric
19098	19098	2 utility in whose service area the customer is located for any
19099	19099	3 portion of the customer's electric power and energy
19100	19100	4 requirements formerly obtained from those facilities
19101	19101	5 (including that amount purchased from the utility in lieu of
19102	19102	6 such generation and not as standby power purchases, under a
19103	19103	7 cogeneration displacement tariff in effect as of the effective
19104	19104	8 date of this amendatory Act of 1997), the transition charges
19105	19105	9 otherwise applicable pursuant to subsections (f), (g), or (h)
19106	19106	10 of this Section shall not be applicable in any year to that
19107	19107	11 portion of the customer's electric power and energy
19108	19108	12 requirements formerly obtained from those facilities,
19109	19109	13 provided, that for purposes of this subsection (j), such
19110	19110	14 portion shall not exceed the average number of kilowatt-hours
19111	19111	15 per year obtained from the cogeneration or self-generation
19112	19112	16 facilities during the 3 years prior to the date on which the
19113	19113	17 customer became eligible for delivery services, except as
19114	19114	18 provided in subsection (f) of Section 16-110.
19115	19115	19 (k) The electric utility shall be entitled to recover
19116	19116	20 through tariffed charges all of the costs associated with the
19117	19117	21 purchase of zero emission credits from zero emission
19118	19118	22 facilities to meet the requirements of subsection (d-5) of
19119	19119	23 Section 1-75 of the Illinois Power Agency Act and all of the
19120	19120	24 costs associated with the purchase of carbon mitigation
19121	19121	25 credits from carbon-free energy resources to meet the
19122	19122	26 requirements of subsection (d-10) of Section 1-75 of the
19123	19123
19124	19124
19125	19125
19126	19126
19127	19127
19128	19128	HB3779 - 532 - LRB104 11172 AAS 21254 b
19129	19129
19130	19130
19131	19131	HB3779- 533 -LRB104 11172 AAS 21254 b HB3779 - 533 - LRB104 11172 AAS 21254 b
19132	19132	HB3779 - 533 - LRB104 11172 AAS 21254 b
19133	19133	1 Illinois Power Agency Act. Such costs shall include the costs
19134	19134	2 of procuring the zero emission credits and carbon mitigation
19135	19135	3 credits from carbon-free energy resources, as well as the
19136	19136	4 reasonable costs that the utility incurs as part of the
19137	19137	5 procurement processes and to implement and comply with plans
19138	19138	6 and processes approved by the Commission under subsections
19139	19139	7 (d-5) and (d-10). The costs shall be allocated across all
19140	19140	8 retail customers through a single, uniform cents per
19141	19141	9 kilowatt-hour charge applicable to all retail customers, which
19142	19142	10 shall appear as a separate line item on each customer's bill.
19143	19143	11 Beginning June 1, 2017, the electric utility shall be entitled
19144	19144	12 to recover through tariffed charges all of the costs
19145	19145	13 associated with the purchase of renewable energy resources to
19146	19146	14 meet the renewable energy resource standards of subsection (c)
19147	19147	15 of Section 1-75 of the Illinois Power Agency Act, under
19148	19148	16 procurement plans as approved in accordance with that Section
19149	19149	17 and Section 16-111.5 of this Act. Such costs shall include the
19150	19150	18 costs of procuring the renewable energy resources, as well as
19151	19151	19 the reasonable costs that the utility incurs as part of the
19152	19152	20 procurement processes and to implement and comply with plans
19153	19153	21 and processes approved by the Commission under such Sections.
19154	19154	22 The costs associated with the purchase of renewable energy
19155	19155	23 resources shall be allocated across all retail customers in
19156	19156	24 proportion to the amount of renewable energy resources the
19157	19157	25 utility procures for such customers through a single, uniform
19158	19158	26 cents per kilowatt-hour charge applicable to such retail
19159	19159
19160	19160
19161	19161
19162	19162
19163	19163
19164	19164	HB3779 - 533 - LRB104 11172 AAS 21254 b
19165	19165
19166	19166
19167	19167	HB3779- 534 -LRB104 11172 AAS 21254 b HB3779 - 534 - LRB104 11172 AAS 21254 b
19168	19168	HB3779 - 534 - LRB104 11172 AAS 21254 b
19169	19169	1 customers, which shall appear as a separate line item on each
19170	19170	2 such customer's bill. The credits, costs, and penalties
19171	19171	3 associated with the self-direct renewable portfolio standard
19172	19172	4 compliance program described in subparagraph (R) of paragraph
19173	19173	5 (1) of subsection (c) of Section 1-75 of the Illinois Power
19174	19174	6 Agency Act shall be allocated to approved eligible self-direct
19175	19175	7 customers by the utility in a cents per kilowatt-hour credit,
19176	19176	8 cost, or penalty, which shall appear as a separate line item on
19177	19177	9 each such customer's bill.
19178	19178	10 Notwithstanding whether the Commission has approved the
19179	19179	11 initial long-term renewable resources procurement plan as of
19180	19180	12 June 1, 2017, an electric utility shall place new tariffed
19181	19181	13 charges into effect beginning with the June 2017 monthly
19182	19182	14 billing period, to the extent practicable, to begin recovering
19183	19183	15 the costs of procuring renewable energy resources, as those
19184	19184	16 charges are calculated under the limitations described in
19185	19185	17 subparagraph (E) of paragraph (1) of subsection (c) of Section
19186	19186	18 1-75 of the Illinois Power Agency Act. Notwithstanding the
19187	19187	19 date on which the utility places such new tariffed charges
19188	19188	20 into effect, the utility shall be permitted to collect the
19189	19189	21 charges under such tariff as if the tariff had been in effect
19190	19190	22 beginning with the first day of the June 2017 monthly billing
19191	19191	23 period. For the delivery years commencing June 1, 2017, June
19192	19192	24 1, 2018, June 1, 2019, and each delivery year thereafter, the
19193	19193	25 electric utility shall deposit into a separate interest
19194	19194	26 bearing account of a financial institution the monies
19195	19195
19196	19196
19197	19197
19198	19198
19199	19199
19200	19200	HB3779 - 534 - LRB104 11172 AAS 21254 b
19201	19201
19202	19202
19203	19203	HB3779- 535 -LRB104 11172 AAS 21254 b HB3779 - 535 - LRB104 11172 AAS 21254 b
19204	19204	HB3779 - 535 - LRB104 11172 AAS 21254 b
19205	19205	1 collected under the tariffed charges. Money collected from
19206	19206	2 customers for the procurement of renewable energy resources in
19207	19207	3 a given delivery year may be spent by the utility for the
19208	19208	4 procurement of renewable resources over any of the following 5
19209	19209	5 delivery years, after which unspent money shall be credited
19210	19210	6 back to retail customers. The electric utility shall spend all
19211	19211	7 money collected in earlier delivery years that has not yet
19212	19212	8 been returned to customers, first, before spending money
19213	19213	9 collected in later delivery years. Any interest earned shall
19214	19214	10 be credited back to retail customers under the reconciliation
19215	19215	11 proceeding provided for in this subsection (k), provided that
19216	19216	12 the electric utility shall first be reimbursed from the
19217	19217	13 interest for the administrative costs that it incurs to
19218	19218	14 administer and manage the account. Any taxes due on the funds
19219	19219	15 in the account, or interest earned on it, will be paid from the
19220	19220	16 account or, if insufficient monies are available in the
19221	19221	17 account, from the monies collected under the tariffed charges
19222	19222	18 to recover the costs of procuring renewable energy resources.
19223	19223	19 Monies deposited in the account shall be subject to the
19224	19224	20 review, reconciliation, and true-up process described in this
19225	19225	21 subsection (k) that is applicable to the funds collected and
19226	19226	22 costs incurred for the procurement of renewable energy
19227	19227	23 resources.
19228	19228	24 The electric utility shall be entitled to recover all of
19229	19229	25 the costs identified in this subsection (k) through automatic
19230	19230	26 adjustment clause tariffs applicable to all of the utility's
19231	19231
19232	19232
19233	19233
19234	19234
19235	19235
19236	19236	HB3779 - 535 - LRB104 11172 AAS 21254 b
19237	19237
19238	19238
19239	19239	HB3779- 536 -LRB104 11172 AAS 21254 b HB3779 - 536 - LRB104 11172 AAS 21254 b
19240	19240	HB3779 - 536 - LRB104 11172 AAS 21254 b
19241	19241	1 retail customers that allow the electric utility to adjust its
19242	19242	2 tariffed charges consistent with this subsection (k). The
19243	19243	3 determination as to whether any excess funds were collected
19244	19244	4 during a given delivery year for the purchase of renewable
19245	19245	5 energy resources, and the crediting of any excess funds back
19246	19246	6 to retail customers, shall not be made until after the close of
19247	19247	7 the delivery year, which will ensure that the maximum amount
19248	19248	8 of funds is available to implement the approved long-term
19249	19249	9 renewable resources procurement plan during a given delivery
19250	19250	10 year. The amount of excess funds eligible to be credited back
19251	19251	11 to retail customers shall be reduced by an amount equal to the
19252	19252	12 payment obligations required by any contracts entered into by
19253	19253	13 an electric utility under contracts described in subsection
19254	19254	14 (b) of Section 1-56 and subsection (c) of Section 1-75 of the
19255	19255	15 Illinois Power Agency Act, even if such payments have not yet
19256	19256	16 been made and regardless of the delivery year in which those
19257	19257	17 payment obligations were incurred. Notwithstanding anything to
19258	19258	18 the contrary, including in tariffs authorized by this
19259	19259	19 subsection (k) in effect before the effective date of this
19260	19260	20 amendatory Act of the 102nd General Assembly, all unspent
19261	19261	21 funds as of May 31, 2021, excluding any funds credited to
19262	19262	22 customers during any utility billing cycle that commences
19263	19263	23 prior to the effective date of this amendatory Act of the 102nd
19264	19264	24 General Assembly, shall remain in the utility account and
19265	19265	25 shall on a first in, first out basis be used toward utility
19266	19266	26 payment obligations under contracts described in subsection
19267	19267
19268	19268
19269	19269
19270	19270
19271	19271
19272	19272	HB3779 - 536 - LRB104 11172 AAS 21254 b
19273	19273
19274	19274
19275	19275	HB3779- 537 -LRB104 11172 AAS 21254 b HB3779 - 537 - LRB104 11172 AAS 21254 b
19276	19276	HB3779 - 537 - LRB104 11172 AAS 21254 b
19277	19277	1 (b) of Section 1-56 and subsection (c) of Section 1-75 of the
19278	19278	2 Illinois Power Agency Act. The electric utility's collections
19279	19279	3 under such automatic adjustment clause tariffs to recover the
19280	19280	4 costs of renewable energy resources, zero emission credits
19281	19281	5 from zero emission facilities, and carbon mitigation credits
19282	19282	6 from carbon-free energy resources shall be subject to separate
19283	19283	7 annual review, reconciliation, and true-up against actual
19284	19284	8 costs by the Commission under a procedure that shall be
19285	19285	9 specified in the electric utility's automatic adjustment
19286	19286	10 clause tariffs and that shall be approved by the Commission in
19287	19287	11 connection with its approval of such tariffs. The procedure
19288	19288	12 shall provide that any difference between the electric
19289	19289	13 utility's collections for zero emission credits and carbon
19290	19290	14 mitigation credits under the automatic adjustment charges for
19291	19291	15 an annual period and the electric utility's actual costs of
19292	19292	16 zero emission credits from zero emission facilities and carbon
19293	19293	17 mitigation credits from carbon-free energy resources for that
19294	19294	18 same annual period shall be refunded to or collected from, as
19295	19295	19 applicable, the electric utility's retail customers in
19296	19296	20 subsequent periods.
19297	19297	21 Nothing in this subsection (k) is intended to affect,
19298	19298	22 limit, or change the right of the electric utility to recover
19299	19299	23 the costs associated with the procurement of renewable energy
19300	19300	24 resources for periods commencing before, on, or after June 1,
19301	19301	25 2017, as otherwise provided in the Illinois Power Agency Act.
19302	19302	26 The funding available under this subsection (k), if any,
19303	19303
19304	19304
19305	19305
19306	19306
19307	19307
19308	19308	HB3779 - 537 - LRB104 11172 AAS 21254 b
19309	19309
19310	19310
19311	19311	HB3779- 538 -LRB104 11172 AAS 21254 b HB3779 - 538 - LRB104 11172 AAS 21254 b
19312	19312	HB3779 - 538 - LRB104 11172 AAS 21254 b
19313	19313	1 for the programs described under subsection (b) of Section
19314	19314	2 1-56 of the Illinois Power Agency Act shall not reduce the
19315	19315	3 amount of funding for the programs described in subparagraph
19316	19316	4 (O) of paragraph (1) of subsection (c) of Section 1-75 of the
19317	19317	5 Illinois Power Agency Act. If funding is available under this
19318	19318	6 subsection (k) for programs described under subsection (b) of
19319	19319	7 Section 1-56 of the Illinois Power Agency Act, then the
19320	19320	8 long-term renewable resources plan shall provide for the
19321	19321	9 Agency to procure contracts in an amount that does not exceed
19322	19322	10 the funding, and the contracts approved by the Commission
19323	19323	11 shall be executed by the applicable utility or utilities.
19324	19324	12 The electric utility shall be entitled to recover through
19325	19325	13 tariffed charges all of the costs associated with the
19326	19326	14 procurement of energy storage resources to meet the
19327	19327	15 requirements of Section 1-93 of the Illinois Power Agency Act
19328	19328	16 under energy storage procurement plans as approved in
19329	19329	17 accordance with that Section and Section 16-111.5 of this Act.
19330	19330	18 These costs shall include the costs of procuring energy
19331	19331	19 storage resources and the reasonable costs that the utility
19332	19332	20 incurs as part of the procurement processes and implementing
19333	19333	21 and complying with energy storage procurement plans and
19334	19334	22 processes approved by the Commission. The costs associated
19335	19335	23 with the procurement of energy storage resources shall be
19336	19336	24 allocated across all retail customers in proportion to the
19337	19337	25 energy storage resources the electric utility procures for the
19338	19338	26 customers through a single, uniform cents per kilowatt-hour
19339	19339
19340	19340
19341	19341
19342	19342
19343	19343
19344	19344	HB3779 - 538 - LRB104 11172 AAS 21254 b
19345	19345
19346	19346
19347	19347	HB3779- 539 -LRB104 11172 AAS 21254 b HB3779 - 539 - LRB104 11172 AAS 21254 b
19348	19348	HB3779 - 539 - LRB104 11172 AAS 21254 b
19349	19349	1 charge applicable to the retail customers, which shall appear
19350	19350	2 as a separate line item on each customer's bill.
19351	19351	3 (l) A utility that has terminated any contract executed
19352	19352	4 under subsection (d-5) or (d-10) of Section 1-75 of the
19353	19353	5 Illinois Power Agency Act shall be entitled to recover any
19354	19354	6 remaining balance associated with the purchase of zero
19355	19355	7 emission credits prior to such termination, and such utility
19356	19356	8 shall also apply a credit to its retail customer bills in the
19357	19357	9 event of any over-collection.
19358	19358	10 (m)(1) An electric utility that recovers its costs of
19359	19359	11 procuring zero emission credits from zero emission facilities
19360	19360	12 through a cents-per-kilowatthour charge under subsection (k)
19361	19361	13 of this Section shall be subject to the requirements of this
19362	19362	14 subsection (m). Notwithstanding anything to the contrary, such
19363	19363	15 electric utility shall, beginning on April 30, 2018, and each
19364	19364	16 April 30 thereafter until April 30, 2026, calculate whether
19365	19365	17 any reduction must be applied to such cents-per-kilowatthour
19366	19366	18 charge that is paid by retail customers of the electric
19367	19367	19 utility that have opted out of subsections (a) through (j) of
19368	19368	20 Section 8-103B of this Act under subsection (l) of Section
19369	19369	21 8-103B. Such charge shall be reduced for such customers for
19370	19370	22 the next delivery year commencing on June 1 based on the amount
19371	19371	23 necessary, if any, to limit the annual estimated average net
19372	19372	24 increase for the prior calendar year due to the future energy
19373	19373	25 investment costs to no more than 1.3% of 5.98 cents per
19374	19374	26 kilowatt-hour, which is the average amount paid per
19375	19375
19376	19376
19377	19377
19378	19378
19379	19379
19380	19380	HB3779 - 539 - LRB104 11172 AAS 21254 b
19381	19381
19382	19382
19383	19383	HB3779- 540 -LRB104 11172 AAS 21254 b HB3779 - 540 - LRB104 11172 AAS 21254 b
19384	19384	HB3779 - 540 - LRB104 11172 AAS 21254 b
19385	19385	1 kilowatthour for electric service during the year ending
19386	19386	2 December 31, 2015 by Illinois industrial retail customers, as
19387	19387	3 reported to the Edison Electric Institute.
19388	19388	4 The calculations required by this subsection (m) shall be
19389	19389	5 made only once for each year, and no subsequent rate impact
19390	19390	6 determinations shall be made.
19391	19391	7 (2) For purposes of this Section, "future energy
19392	19392	8 investment costs" shall be calculated by subtracting the
19393	19393	9 cents-per-kilowatthour charge identified in subparagraph (A)
19394	19394	10 of this paragraph (2) from the sum of the
19395	19395	11 cents-per-kilowatthour charges identified in subparagraph (B)
19396	19396	12 of this paragraph (2):
19397	19397	13 (A) The cents-per-kilowatthour charge identified in
19398	19398	14 the electric utility's tariff placed into effect under
19399	19399	15 Section 8-103 of the Public Utilities Act that, on
19400	19400	16 December 1, 2016, was applicable to those retail customers
19401	19401	17 that have opted out of subsections (a) through (j) of
19402	19402	18 Section 8-103B of this Act under subsection (l) of Section
19403	19403	19 8-103B.
19404	19404	20 (B) The sum of the following cents-per-kilowatthour
19405	19405	21 charges applicable to those retail customers that have
19406	19406	22 opted out of subsections (a) through (j) of Section 8-103B
19407	19407	23 of this Act under subsection (l) of Section 8-103B,
19408	19408	24 provided that if one or more of the following charges has
19409	19409	25 been in effect and applied to such customers for more than
19410	19410	26 one calendar year, then each charge shall be equal to the
19411	19411
19412	19412
19413	19413
19414	19414
19415	19415
19416	19416	HB3779 - 540 - LRB104 11172 AAS 21254 b
19417	19417
19418	19418
19419	19419	HB3779- 541 -LRB104 11172 AAS 21254 b HB3779 - 541 - LRB104 11172 AAS 21254 b
19420	19420	HB3779 - 541 - LRB104 11172 AAS 21254 b
19421	19421	1 average of the charges applied over a period that
19422	19422	2 commences with the calendar year ending December 31, 2017
19423	19423	3 and ends with the most recently completed calendar year
19424	19424	4 prior to the calculation required by this subsection (m):
19425	19425	5 (i) the cents-per-kilowatthour charge to recover
19426	19426	6 the costs incurred by the utility under subsection
19427	19427	7 (d-5) of Section 1-75 of the Illinois Power Agency
19428	19428	8 Act, adjusted for any reductions required under this
19429	19429	9 subsection (m); and
19430	19430	10 (ii) the cents-per-kilowatthour charge to recover
19431	19431	11 the costs incurred by the utility under Section
19432	19432	12 16-107.6 of the Public Utilities Act.
19433	19433	13 If no charge was applied for a given calendar year
19434	19434	14 under item (i) or (ii) of this subparagraph (B), then the
19435	19435	15 value of the charge for that year shall be zero.
19436	19436	16 (3) If a reduction is required by the calculation
19437	19437	17 performed under this subsection (m), then the amount of the
19438	19438	18 reduction shall be multiplied by the number of years reflected
19439	19439	19 in the averages calculated under subparagraph (B) of paragraph
19440	19440	20 (2) of this subsection (m). Such reduction shall be applied to
19441	19441	21 the cents-per-kilowatthour charge that is applicable to those
19442	19442	22 retail customers that have opted out of subsections (a)
19443	19443	23 through (j) of Section 8-103B of this Act under subsection (l)
19444	19444	24 of Section 8-103B beginning with the next delivery year
19445	19445	25 commencing after the date of the calculation required by this
19446	19446	26 subsection (m).
19447	19447
19448	19448
19449	19449
19450	19450
19451	19451
19452	19452	HB3779 - 541 - LRB104 11172 AAS 21254 b
19453	19453
19454	19454
19455	19455	HB3779- 542 -LRB104 11172 AAS 21254 b HB3779 - 542 - LRB104 11172 AAS 21254 b
19456	19456	HB3779 - 542 - LRB104 11172 AAS 21254 b
19457	19457	1 (4) The electric utility shall file a notice with the
19458	19458	2 Commission on May 1 of 2018 and each May 1 thereafter until May
19459	19459	3 1, 2026 containing the reduction, if any, which must be
19460	19460	4 applied for the delivery year which begins in the year of the
19461	19461	5 filing. The notice shall contain the calculations made
19462	19462	6 pursuant to this Section. By October 1 of each year beginning
19463	19463	7 in 2018, each electric utility shall notify the Commission if
19464	19464	8 it appears, based on an estimate of the calculation required
19465	19465	9 in this subsection (m), that a reduction will be required in
19466	19466	10 the next year.
19467	19467	11 (Source: P.A. 102-662, eff. 9-15-21.)
19468	19468	12 (220 ILCS 5/16-108.30)
19469	19469	13 Sec. 16-108.30. Energy Transition Assistance Fund.
19470	19470	14 (a) The Energy Transition Assistance Fund is hereby
19471	19471	15 created as a special fund in the State Treasury. The Energy
19472	19472	16 Transition Assistance Fund is authorized to receive moneys
19473	19473	17 collected pursuant to this Section. Subject to appropriation,
19474	19474	18 the Department of Commerce and Economic Opportunity shall use
19475	19475	19 moneys from the Energy Transition Assistance Fund consistent
19476	19476	20 with the purposes of this Act.
19477	19477	21 (b) An electric utility serving more than 500,000
19478	19478	22 customers in the State shall assess an energy transition
19479	19479	23 assistance charge on all its retail customers for the Energy
19480	19480	24 Transition Assistance Fund. The utility's total charge shall
19481	19481	25 be set based upon the value determined by the Department of
19482	19482
19483	19483
19484	19484
19485	19485
19486	19486
19487	19487	HB3779 - 542 - LRB104 11172 AAS 21254 b
19488	19488
19489	19489
19490	19490	HB3779- 543 -LRB104 11172 AAS 21254 b HB3779 - 543 - LRB104 11172 AAS 21254 b
19491	19491	HB3779 - 543 - LRB104 11172 AAS 21254 b
19492	19492	1 Commerce and Economic Opportunity pursuant to subsection (d)
19493	19493	2 or (e), as applicable, of Section 605-1075 of the Department
19494	19494	3 of Commerce and Economic Opportunity Law of the Civil
19495	19495	4 Administrative Code of Illinois. For each utility, the charge
19496	19496	5 shall be recovered through a single, uniform cents per
19497	19497	6 kilowatt-hour charge applicable to all retail customers. For
19498	19498	7 each utility, the charge shall not exceed 1.3% of the amount
19499	19499	8 paid per kilowatthour by eligible retail customers during the
19500	19500	9 year ending May 31, 2009.
19501	19501	10 (c) Within 75 days of the effective date of this
19502	19502	11 amendatory Act of the 102nd General Assembly, each electric
19503	19503	12 utility serving more than 500,000 customers in the State shall
19504	19504	13 file with the Illinois Commerce Commission tariffs
19505	19505	14 incorporating the energy transition assistance charge in other
19506	19506	15 charges stated in such tariffs, which energy transition
19507	19507	16 assistance charges shall become effective no later than the
19508	19508	17 beginning of the first billing cycle that begins on or after
19509	19509	18 January 1, 2022. Each electric utility serving more than
19510	19510	19 500,000 customers in the State shall, prior to the beginning
19511	19511	20 of each calendar year starting with calendar year 2023, file
19512	19512	21 with the Illinois Commerce Commission tariff revisions to
19513	19513	22 incorporate annual revisions to the energy transition
19514	19514	23 assistance charge as prescribed by the Department of Commerce
19515	19515	24 and Economic Opportunity pursuant to Section 605-1075 of the
19516	19516	25 Department of Commerce and Economic Opportunity Law of the
19517	19517	26 Civil Administrative Code of Illinois so that such revision
19518	19518
19519	19519
19520	19520
19521	19521
19522	19522
19523	19523	HB3779 - 543 - LRB104 11172 AAS 21254 b
19524	19524
19525	19525
19526	19526	HB3779- 544 -LRB104 11172 AAS 21254 b HB3779 - 544 - LRB104 11172 AAS 21254 b
19527	19527	HB3779 - 544 - LRB104 11172 AAS 21254 b
19528	19528	1 becomes effective no later than the beginning of the first
19529	19529	2 billing cycle in each respective year. Within 75 days of the
19530	19530	3 effective date of this amendatory Act of the 104th General
19531	19531	4 Assembly, each electric utility serving more than 500,000
19532	19532	5 customers in the State shall file with the Illinois Commerce
19533	19533	6 Commission tariffs incorporating the additional energy
19534	19534	7 transition charge required under this amendatory Act, which
19535	19535	8 additional energy transition assistance charges shall become
19536	19536	9 effective no later than the beginning of the first billing
19537	19537	10 cycle that begins on or after September 1, 2025.
19538	19538	11 (d) The energy transition assistance charge shall be
19539	19539	12 considered a charge for public utility service.
19540	19540	13 (e) By the 20th day of the month following the month in
19541	19541	14 which the charges imposed by this Section were collected, each
19542	19542	15 electric utility serving more than 500,000 customers in the
19543	19543	16 State shall remit to Department of Revenue all moneys received
19544	19544	17 as payment of the energy transition assistance charge on a
19545	19545	18 return prescribed and furnished by the Department of Revenue
19546	19546	19 showing such information as the Department of Revenue may
19547	19547	20 reasonably require. If a customer makes a partial payment, a
19548	19548	21 public utility may apply such partial payments first to
19549	19549	22 amounts owed to the utility. No customer may be subjected to
19550	19550	23 disconnection of his or her utility service for failure to pay
19551	19551	24 the energy transition assistance charge.
19552	19552	25 If any payment provided for in this subsection exceeds the
19553	19553	26 electric utility's liabilities under this Act, as shown on an
19554	19554
19555	19555
19556	19556
19557	19557
19558	19558
19559	19559	HB3779 - 544 - LRB104 11172 AAS 21254 b
19560	19560
19561	19561
19562	19562	HB3779- 545 -LRB104 11172 AAS 21254 b HB3779 - 545 - LRB104 11172 AAS 21254 b
19563	19563	HB3779 - 545 - LRB104 11172 AAS 21254 b
19564	19564	1 original return, the Department may authorize the electric
19565	19565	2 utility to credit such excess payment against liability
19566	19566	3 subsequently to be remitted to the Department under this Act,
19567	19567	4 in accordance with reasonable rules adopted by the Department.
19568	19568	5 All the provisions of Sections 4, 5, 5a, 5b, 5c, 5d, 5e,
19569	19569	6 5f, 5g, 5i, 5j, 6, 6a, 6b, 6c, 7, 8, 9, 10, 11, 11a, 12, and 13
19570	19570	7 of the Retailers' Occupation Tax Act that are not inconsistent
19571	19571	8 with this Act apply, as far as practicable, to the charge
19572	19572	9 imposed by this Act to the same extent as if those provisions
19573	19573	10 were included in this Act. References in the incorporated
19574	19574	11 Sections of the Retailers' Occupation Tax Act to retailers, to
19575	19575	12 sellers, or to persons engaged in the business of selling
19576	19576	13 tangible personal property mean persons required to remit the
19577	19577	14 charge imposed under this Act.
19578	19578	15 (f) The Department of Revenue shall deposit into the
19579	19579	16 Energy Transition Assistance Fund all moneys remitted to it in
19580	19580	17 accordance with this Section.
19581	19581	18 (g) The Department of Revenue may establish such rules as
19582	19582	19 it deems necessary to implement this Section.
19583	19583	20 (h) The Department of Commerce and Economic Opportunity
19584	19584	21 may establish such rules as it deems necessary to implement
19585	19585	22 this Section.
19586	19586	23 (Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
19587	19587	24 (220 ILCS 5/16-111.5)
19588	19588	25 Sec. 16-111.5. Provisions relating to procurement.
19589	19589
19590	19590
19591	19591
19592	19592
19593	19593
19594	19594	HB3779 - 545 - LRB104 11172 AAS 21254 b
19595	19595
19596	19596
19597	19597	HB3779- 546 -LRB104 11172 AAS 21254 b HB3779 - 546 - LRB104 11172 AAS 21254 b
19598	19598	HB3779 - 546 - LRB104 11172 AAS 21254 b
19599	19599	1 (a) An electric utility that on December 31, 2005 served
19600	19600	2 at least 100,000 customers in Illinois shall procure power and
19601	19601	3 energy for its eligible retail customers in accordance with
19602	19602	4 the applicable provisions set forth in Section 1-75 of the
19603	19603	5 Illinois Power Agency Act and this Section. Beginning with the
19604	19604	6 delivery year commencing on June 1, 2017, such electric
19605	19605	7 utility shall also procure zero emission credits from zero
19606	19606	8 emission facilities in accordance with the applicable
19607	19607	9 provisions set forth in Section 1-75 of the Illinois Power
19608	19608	10 Agency Act, and, for years beginning on or after June 1, 2017,
19609	19609	11 the utility shall procure renewable energy resources in
19610	19610	12 accordance with the applicable provisions set forth in Section
19611	19611	13 1-75 of the Illinois Power Agency Act and this Section.
19612	19612	14 Beginning with the delivery year commencing on June 1, 2022,
19613	19613	15 an electric utility serving over 3,000,000 customers shall
19614	19614	16 also procure carbon mitigation credits from carbon-free energy
19615	19615	17 resources in accordance with the applicable provisions set
19616	19616	18 forth in Section 1-75 of the Illinois Power Agency Act and this
19617	19617	19 Section. A small multi-jurisdictional electric utility that on
19618	19618	20 December 31, 2005 served less than 100,000 customers in
19619	19619	21 Illinois may elect to procure power and energy for all or a
19620	19620	22 portion of its eligible Illinois retail customers in
19621	19621	23 accordance with the applicable provisions set forth in this
19622	19622	24 Section and Section 1-75 of the Illinois Power Agency Act.
19623	19623	25 This Section shall not apply to a small multi-jurisdictional
19624	19624	26 utility until such time as a small multi-jurisdictional
19625	19625
19626	19626
19627	19627
19628	19628
19629	19629
19630	19630	HB3779 - 546 - LRB104 11172 AAS 21254 b
19631	19631
19632	19632
19633	19633	HB3779- 547 -LRB104 11172 AAS 21254 b HB3779 - 547 - LRB104 11172 AAS 21254 b
19634	19634	HB3779 - 547 - LRB104 11172 AAS 21254 b
19635	19635	1 utility requests the Illinois Power Agency to prepare a
19636	19636	2 procurement plan for its eligible retail customers. "Eligible
19637	19637	3 retail customers" for the purposes of this Section means those
19638	19638	4 retail customers that purchase power and energy from the
19639	19639	5 electric utility under fixed-price bundled service tariffs,
19640	19640	6 other than those retail customers whose service is declared or
19641	19641	7 deemed competitive under Section 16-113 and those other
19642	19642	8 customer groups specified in this Section, including
19643	19643	9 self-generating customers, customers electing hourly pricing,
19644	19644	10 or those customers who are otherwise ineligible for
19645	19645	11 fixed-price bundled tariff service. For those customers that
19646	19646	12 are excluded from the procurement plan's electric supply
19647	19647	13 service requirements, and the utility shall procure any supply
19648	19648	14 requirements, including capacity, ancillary services, and
19649	19649	15 hourly priced energy, in the applicable markets as needed to
19650	19650	16 serve those customers, provided that the utility may include
19651	19651	17 in its procurement plan load requirements for the load that is
19652	19652	18 associated with those retail customers whose service has been
19653	19653	19 declared or deemed competitive pursuant to Section 16-113 of
19654	19654	20 this Act to the extent that those customers are purchasing
19655	19655	21 power and energy during one of the transition periods
19656	19656	22 identified in subsection (b) of Section 16-113 of this Act.
19657	19657	23 (b) A procurement plan shall be prepared for each electric
19658	19658	24 utility consistent with the applicable requirements of the
19659	19659	25 Illinois Power Agency Act and this Section. For purposes of
19660	19660	26 this Section, Illinois electric utilities that are affiliated
19661	19661
19662	19662
19663	19663
19664	19664
19665	19665
19666	19666	HB3779 - 547 - LRB104 11172 AAS 21254 b
19667	19667
19668	19668
19669	19669	HB3779- 548 -LRB104 11172 AAS 21254 b HB3779 - 548 - LRB104 11172 AAS 21254 b
19670	19670	HB3779 - 548 - LRB104 11172 AAS 21254 b
19671	19671	1 by virtue of a common parent company are considered to be a
19672	19672	2 single electric utility. Small multi-jurisdictional utilities
19673	19673	3 may request a procurement plan for a portion of or all of its
19674	19674	4 Illinois load. Each procurement plan shall analyze the
19675	19675	5 projected balance of supply and demand for those retail
19676	19676	6 customers to be included in the plan's electric supply service
19677	19677	7 requirements over a 5-year period, with the first planning
19678	19678	8 year beginning on June 1 of the year following the year in
19679	19679	9 which the plan is filed. The plan shall specifically identify
19680	19680	10 the wholesale products to be procured following plan approval,
19681	19681	11 and shall follow all the requirements set forth in the Public
19682	19682	12 Utilities Act and all applicable State and federal laws,
19683	19683	13 statutes, rules, or regulations, as well as Commission orders.
19684	19684	14 Nothing in this Section precludes consideration of contracts
19685	19685	15 longer than 5 years and related forecast data. Unless
19686	19686	16 specified otherwise in this Section, in the procurement plan
19687	19687	17 or in the implementing tariff, any procurement occurring in
19688	19688	18 accordance with this plan shall be competitively bid through a
19689	19689	19 request for proposals process. Approval and implementation of
19690	19690	20 the procurement plan shall be subject to review and approval
19691	19691	21 by the Commission according to the provisions set forth in
19692	19692	22 this Section. A procurement plan shall include each of the
19693	19693	23 following components:
19694	19694	24 (1) Hourly load analysis. This analysis shall include:
19695	19695	25 (i) multi-year historical analysis of hourly
19696	19696	26 loads;
19697	19697
19698	19698
19699	19699
19700	19700
19701	19701
19702	19702	HB3779 - 548 - LRB104 11172 AAS 21254 b
19703	19703
19704	19704
19705	19705	HB3779- 549 -LRB104 11172 AAS 21254 b HB3779 - 549 - LRB104 11172 AAS 21254 b
19706	19706	HB3779 - 549 - LRB104 11172 AAS 21254 b
19707	19707	1 (ii) switching trends and competitive retail
19708	19708	2 market analysis;
19709	19709	3 (iii) known or projected changes to future loads;
19710	19710	4 and
19711	19711	5 (iv) growth forecasts by customer class.
19712	19712	6 (2) Analysis of the impact of any demand side and
19713	19713	7 renewable energy initiatives. This analysis shall include:
19714	19714	8 (i) the impact of demand response programs and
19715	19715	9 energy efficiency programs, both current and
19716	19716	10 projected; for small multi-jurisdictional utilities,
19717	19717	11 the impact of demand response and energy efficiency
19718	19718	12 programs approved pursuant to Section 8-408 of this
19719	19719	13 Act, both current and projected; and
19720	19720	14 (ii) supply side needs that are projected to be
19721	19721	15 offset by purchases of renewable energy resources, if
19722	19722	16 any.
19723	19723	17 (3) A plan for meeting the expected load requirements
19724	19724	18 that will not be met through preexisting contracts. This
19725	19725	19 plan shall include:
19726	19726	20 (i) definitions of the different Illinois retail
19727	19727	21 customer classes for which supply is being purchased;
19728	19728	22 (ii) the proposed mix of demand-response products
19729	19729	23 for which contracts will be executed during the next
19730	19730	24 year. For small multi-jurisdictional electric
19731	19731	25 utilities that on December 31, 2005 served fewer than
19732	19732	26 100,000 customers in Illinois, these shall be defined
19733	19733
19734	19734
19735	19735
19736	19736
19737	19737
19738	19738	HB3779 - 549 - LRB104 11172 AAS 21254 b
19739	19739
19740	19740
19741	19741	HB3779- 550 -LRB104 11172 AAS 21254 b HB3779 - 550 - LRB104 11172 AAS 21254 b
19742	19742	HB3779 - 550 - LRB104 11172 AAS 21254 b
19743	19743	1 as demand-response products offered in an energy
19744	19744	2 efficiency plan approved pursuant to Section 8-408 of
19745	19745	3 this Act. The cost-effective demand-response measures
19746	19746	4 shall be procured whenever the cost is lower than
19747	19747	5 procuring comparable capacity products, provided that
19748	19748	6 such products shall:
19749	19749	7 (A) be procured by a demand-response provider
19750	19750	8 from those retail customers included in the plan's
19751	19751	9 electric supply service requirements;
19752	19752	10 (B) at least satisfy the demand-response
19753	19753	11 requirements of the regional transmission
19754	19754	12 organization market in which the utility's service
19755	19755	13 territory is located, including, but not limited
19756	19756	14 to, any applicable capacity or dispatch
19757	19757	15 requirements;
19758	19758	16 (C) provide for customers' participation in
19759	19759	17 the stream of benefits produced by the
19760	19760	18 demand-response products;
19761	19761	19 (D) provide for reimbursement by the
19762	19762	20 demand-response provider of the utility for any
19763	19763	21 costs incurred as a result of the failure of the
19764	19764	22 supplier of such products to perform its
19765	19765	23 obligations thereunder; and
19766	19766	24 (E) meet the same credit requirements as apply
19767	19767	25 to suppliers of capacity, in the applicable
19768	19768	26 regional transmission organization market;
19769	19769
19770	19770
19771	19771
19772	19772
19773	19773
19774	19774	HB3779 - 550 - LRB104 11172 AAS 21254 b
19775	19775
19776	19776
19777	19777	HB3779- 551 -LRB104 11172 AAS 21254 b HB3779 - 551 - LRB104 11172 AAS 21254 b
19778	19778	HB3779 - 551 - LRB104 11172 AAS 21254 b
19779	19779	1 (iii) monthly forecasted system supply
19780	19780	2 requirements, including expected minimum, maximum, and
19781	19781	3 average values for the planning period;
19782	19782	4 (iv) the proposed mix and selection of standard
19783	19783	5 wholesale products for which contracts will be
19784	19784	6 executed during the next year, separately or in
19785	19785	7 combination, to meet that portion of its load
19786	19786	8 requirements not met through pre-existing contracts,
19787	19787	9 including but not limited to monthly 5 x 16 peak period
19788	19788	10 block energy, monthly off-peak wrap energy, monthly 7
19789	19789	11 x 24 energy, annual 5 x 16 energy, other standardized
19790	19790	12 energy or capacity products designed to provide
19791	19791	13 eligible retail customer benefits from commercially
19792	19792	14 deployed advanced technologies including but not
19793	19793	15 limited to high voltage direct current converter
19794	19794	16 stations, as such term is defined in Section 1-10 of
19795	19795	17 the Illinois Power Agency Act, whether or not such
19796	19796	18 product is currently available in wholesale markets,
19797	19797	19 annual off-peak wrap energy, annual 7 x 24 energy,
19798	19798	20 monthly capacity, annual capacity, peak load capacity
19799	19799	21 obligations, capacity purchase plan, and ancillary
19800	19800	22 services; however, nothing in this item (iv) precludes
19801	19801	23 consideration of long-term contracts with a length up
19802	19802	24 to and including 20 years for clean energy, as defined
19803	19803	25 in Section 1-10 of the Illinois Power Agency Act, with
19804	19804	26 an appropriate portion of the portfolio to be
19805	19805
19806	19806
19807	19807
19808	19808
19809	19809
19810	19810	HB3779 - 551 - LRB104 11172 AAS 21254 b
19811	19811
19812	19812
19813	19813	HB3779- 552 -LRB104 11172 AAS 21254 b HB3779 - 552 - LRB104 11172 AAS 21254 b
19814	19814	HB3779 - 552 - LRB104 11172 AAS 21254 b
19815	19815	1 allocated to such long-term contracts;
19816	19816	2 (v) proposed term structures for each wholesale
19817	19817	3 product type included in the proposed procurement plan
19818	19818	4 portfolio of products; and
19819	19819	5 (vi) an assessment of the price risk, load
19820	19820	6 uncertainty, and other factors that are associated
19821	19821	7 with the proposed procurement plan; this assessment,
19822	19822	8 to the extent possible, shall include an analysis of
19823	19823	9 the following factors: contract terms, time frames for
19824	19824	10 securing products or services, fuel costs, weather
19825	19825	11 patterns, transmission costs, market conditions, and
19826	19826	12 the governmental regulatory environment; the proposed
19827	19827	13 procurement plan shall also identify alternatives for
19828	19828	14 those portfolio measures that are identified as having
19829	19829	15 significant price risk and mitigation in the form of
19830	19830	16 additional retail customer and ratepayer price,
19831	19831	17 reliability, and environmental benefits from
19832	19832	18 standardized energy products delivered from
19833	19833	19 commercially deployed advanced technologies,
19834	19834	20 including, but not limited to, high voltage direct
19835	19835	21 current converter stations, as such term is defined in
19836	19836	22 Section 1-10 of the Illinois Power Agency Act, whether
19837	19837	23 or not such product is currently available in
19838	19838	24 wholesale markets; and.
19839	19839	25 (vii) for procurement events beginning after May
19840	19840	26 31, 2025, consideration of whether products offered
19841	19841
19842	19842
19843	19843
19844	19844
19845	19845
19846	19846	HB3779 - 552 - LRB104 11172 AAS 21254 b
19847	19847
19848	19848
19849	19849	HB3779- 553 -LRB104 11172 AAS 21254 b HB3779 - 553 - LRB104 11172 AAS 21254 b
19850	19850	HB3779 - 553 - LRB104 11172 AAS 21254 b
19851	19851	1 into the procurement process are renewable energy
19852	19852	2 resources, as defined in Section 1-10 of the Illinois
19853	19853	3 Power Agency Act that might otherwise qualify for the
19854	19854	4 renewable portfolio standard described in
19855	19855	5 subparagraphs (c)(1)(I) and (c)(1)(J) of Section 1-75
19856	19856	6 of the Illinois Power Agency Act where such product or
19857	19857	7 products can be procured at or near the price of
19858	19858	8 nonrenewable energy after taking account of the social
19859	19859	9 cost of carbon as set forth in subparagraph (B) of
19860	19860	10 paragraph (1) of subsection (d-5) of Section 1-75 of
19861	19861	11 the Illinois Power Agency Act. The Agency shall
19862	19862	12 consider fuel volatility, long-term trends in
19863	19863	13 non-renewable energy resource pricing, and the
19864	19864	14 environmental benefits of renewable energy resources
19865	19865	15 when comparing products and may, in doing so, select
19866	19866	16 products comprised of renewable energy resources that
19867	19867	17 are at a higher fixed price over a longer duration.
19868	19868	18 Each product procured shall include all environmental
19869	19869	19 attributes, including, but not limited to, and
19870	19870	20 renewable energy credits, all as defined in Section
19871	19871	21 1-10 of the Illinois Power Agency Act, and all
19872	19872	22 credits, characteristics, benefits, emissions
19873	19873	23 reductions, offsets, and allowances, howsoever
19874	19874	24 entitled, attributable to the generation of the
19875	19875	25 product procured or its displacement of generation.
19876	19876	26 (4) Proposed procedures for balancing loads. The
19877	19877
19878	19878
19879	19879
19880	19880
19881	19881
19882	19882	HB3779 - 553 - LRB104 11172 AAS 21254 b
19883	19883
19884	19884
19885	19885	HB3779- 554 -LRB104 11172 AAS 21254 b HB3779 - 554 - LRB104 11172 AAS 21254 b
19886	19886	HB3779 - 554 - LRB104 11172 AAS 21254 b
19887	19887	1 procurement plan shall include, for load requirements
19888	19888	2 included in the procurement plan, the process for (i)
19889	19889	3 hourly balancing of supply and demand and (ii) the
19890	19890	4 criteria for portfolio re-balancing in the event of
19891	19891	5 significant shifts in load.
19892	19892	6 (5) Long-Term Renewable Resources Procurement Plan.
19893	19893	7 The Agency shall prepare a long-term renewable resources
19894	19894	8 procurement plan for the procurement of renewable energy
19895	19895	9 credits under Sections 1-56 and 1-75 of the Illinois Power
19896	19896	10 Agency Act for delivery beginning in the 2017 delivery
19897	19897	11 year.
19898	19898	12 (i) The initial long-term renewable resources
19899	19899	13 procurement plan and all subsequent revisions shall be
19900	19900	14 subject to review and approval by the Commission. For
19901	19901	15 the purposes of this Section, "delivery year" has the
19902	19902	16 same meaning as in Section 1-10 of the Illinois Power
19903	19903	17 Agency Act. For purposes of this Section, "Agency"
19904	19904	18 shall mean the Illinois Power Agency.
19905	19905	19 (ii) The long-term renewable resources planning
19906	19906	20 process shall be conducted as follows:
19907	19907	21 (A) Electric utilities shall provide a range
19908	19908	22 of load forecasts to the Illinois Power Agency
19909	19909	23 within 45 days of the Agency's request for
19910	19910	24 forecasts, which request shall specify the length
19911	19911	25 and conditions for the forecasts including, but
19912	19912	26 not limited to, the quantity of distributed
19913	19913
19914	19914
19915	19915
19916	19916
19917	19917
19918	19918	HB3779 - 554 - LRB104 11172 AAS 21254 b
19919	19919
19920	19920
19921	19921	HB3779- 555 -LRB104 11172 AAS 21254 b HB3779 - 555 - LRB104 11172 AAS 21254 b
19922	19922	HB3779 - 555 - LRB104 11172 AAS 21254 b
19923	19923	1 generation expected to be interconnected for each
19924	19924	2 year.
19925	19925	3 (B) The Agency shall publish for comment the
19926	19926	4 initial long-term renewable resources procurement
19927	19927	5 plan no later than 120 days after the effective
19928	19928	6 date of this amendatory Act of the 99th General
19929	19929	7 Assembly and shall review, and may revise, the
19930	19930	8 plan at least every 2 years thereafter. To the
19931	19931	9 extent practicable, the Agency shall review and
19932	19932	10 propose any revisions to the long-term renewable
19933	19933	11 energy resources procurement plan in conjunction
19934	19934	12 with the Agency's other planning and approval
19935	19935	13 processes conducted under this Section. The
19936	19936	14 initial long-term renewable resources procurement
19937	19937	15 plan shall:
19938	19938	16 (aa) Identify the procurement programs and
19939	19939	17 competitive procurement events consistent with
19940	19940	18 the applicable requirements of the Illinois
19941	19941	19 Power Agency Act and shall be designed to
19942	19942	20 achieve the goals set forth in subsection (c)
19943	19943	21 of Section 1-75 of that Act.
19944	19944	22 (bb) Include a schedule for procurements
19945	19945	23 for renewable energy credits from
19946	19946	24 utility-scale wind projects, utility-scale
19947	19947	25 solar projects, and brownfield site
19948	19948	26 photovoltaic projects consistent with
19949	19949
19950	19950
19951	19951
19952	19952
19953	19953
19954	19954	HB3779 - 555 - LRB104 11172 AAS 21254 b
19955	19955
19956	19956
19957	19957	HB3779- 556 -LRB104 11172 AAS 21254 b HB3779 - 556 - LRB104 11172 AAS 21254 b
19958	19958	HB3779 - 556 - LRB104 11172 AAS 21254 b
19959	19959	1 subparagraph (G) of paragraph (1) of
19960	19960	2 subsection (c) of Section 1-75 of the Illinois
19961	19961	3 Power Agency Act.
19962	19962	4 (cc) Identify the process whereby the
19963	19963	5 Agency will submit to the Commission for
19964	19964	6 review and approval the proposed contracts to
19965	19965	7 implement the programs required by such plan.
19966	19966	8 Copies of the initial long-term renewable
19967	19967	9 resources procurement plan and all subsequent
19968	19968	10 revisions shall be posted and made publicly
19969	19969	11 available on the Agency's and Commission's
19970	19970	12 websites, and copies shall also be provided to
19971	19971	13 each affected electric utility. An affected
19972	19972	14 utility and other interested parties shall have 45
19973	19973	15 days following the date of posting to provide
19974	19974	16 comment to the Agency on the initial long-term
19975	19975	17 renewable resources procurement plan and all
19976	19976	18 subsequent revisions. All comments submitted to
19977	19977	19 the Agency shall be specific, supported by data or
19978	19978	20 other detailed analyses, and, if objecting to all
19979	19979	21 or a portion of the procurement plan, accompanied
19980	19980	22 by specific alternative wording or proposals. All
19981	19981	23 comments shall be posted on the Agency's and
19982	19982	24 Commission's websites. During this 45-day comment
19983	19983	25 period, the Agency shall hold at least one public
19984	19984	26 hearing within each utility's service area that is
19985	19985
19986	19986
19987	19987
19988	19988
19989	19989
19990	19990	HB3779 - 556 - LRB104 11172 AAS 21254 b
19991	19991
19992	19992
19993	19993	HB3779- 557 -LRB104 11172 AAS 21254 b HB3779 - 557 - LRB104 11172 AAS 21254 b
19994	19994	HB3779 - 557 - LRB104 11172 AAS 21254 b
19995	19995	1 subject to the requirements of this paragraph (5)
19996	19996	2 for the purpose of receiving public comment.
19997	19997	3 Within 21 days following the end of the 45-day
19998	19998	4 review period, the Agency may revise the long-term
19999	19999	5 renewable resources procurement plan based on the
20000	20000	6 comments received and shall file the plan with the
20001	20001	7 Commission for review and approval.
20002	20002	8 (C) Within 14 days after the filing of the
20003	20003	9 initial long-term renewable resources procurement
20004	20004	10 plan or any subsequent revisions, any person
20005	20005	11 objecting to the plan may file an objection with
20006	20006	12 the Commission. Within 21 days after the filing of
20007	20007	13 the plan, the Commission shall determine whether a
20008	20008	14 hearing is necessary. The Commission shall enter
20009	20009	15 its order confirming or modifying the initial
20010	20010	16 long-term renewable resources procurement plan or
20011	20011	17 any subsequent revisions within 120 days after the
20012	20012	18 filing of the plan by the Illinois Power Agency.
20013	20013	19 (D) The Commission shall approve the initial
20014	20014	20 long-term renewable resources procurement plan and
20015	20015	21 any subsequent revisions, including expressly the
20016	20016	22 forecast used in the plan and taking into account
20017	20017	23 that funding will be limited to the amount of
20018	20018	24 revenues actually collected by the utilities, if
20019	20019	25 the Commission determines that the plan will
20020	20020	26 reasonably and prudently accomplish the
20021	20021
20022	20022
20023	20023
20024	20024
20025	20025
20026	20026	HB3779 - 557 - LRB104 11172 AAS 21254 b
20027	20027
20028	20028
20029	20029	HB3779- 558 -LRB104 11172 AAS 21254 b HB3779 - 558 - LRB104 11172 AAS 21254 b
20030	20030	HB3779 - 558 - LRB104 11172 AAS 21254 b
20031	20031	1 requirements of Section 1-56 and subsection (c) of
20032	20032	2 Section 1-75 of the Illinois Power Agency Act. The
20033	20033	3 Commission shall also approve the process for the
20034	20034	4 submission, review, and approval of the proposed
20035	20035	5 contracts to procure renewable energy credits or
20036	20036	6 implement the programs authorized by the
20037	20037	7 Commission pursuant to a long-term renewable
20038	20038	8 resources procurement plan approved under this
20039	20039	9 Section.
20040	20040	10 In approving any long-term renewable resources
20041	20041	11 procurement plan after the effective date of this
20042	20042	12 amendatory Act of the 102nd General Assembly, the
20043	20043	13 Commission shall approve or modify the Agency's
20044	20044	14 proposal for minimum equity standards pursuant to
20045	20045	15 subsection (c-10) of Section 1-75 of the Illinois
20046	20046	16 Power Agency Act. The Commission shall consider
20047	20047	17 any analysis performed by the Agency in developing
20048	20048	18 its proposal, including past performance,
20049	20049	19 availability of equity eligible contractors, and
20050	20050	20 availability of equity eligible persons at the
20051	20051	21 time the long-term renewable resources procurement
20052	20052	22 plan is approved.
20053	20053	23 (iii) The Agency or third parties contracted by
20054	20054	24 the Agency shall implement all programs authorized by
20055	20055	25 the Commission in an approved long-term renewable
20056	20056	26 resources procurement plan without further review and
20057	20057
20058	20058
20059	20059
20060	20060
20061	20061
20062	20062	HB3779 - 558 - LRB104 11172 AAS 21254 b
20063	20063
20064	20064
20065	20065	HB3779- 559 -LRB104 11172 AAS 21254 b HB3779 - 559 - LRB104 11172 AAS 21254 b
20066	20066	HB3779 - 559 - LRB104 11172 AAS 21254 b
20067	20067	1 approval by the Commission. Third parties shall not
20068	20068	2 begin implementing any programs or receive any payment
20069	20069	3 under this Section until the Commission has approved
20070	20070	4 the contract or contracts under the process authorized
20071	20071	5 by the Commission in item (D) of subparagraph (ii) of
20072	20072	6 paragraph (5) of this subsection (b) and the third
20073	20073	7 party and the Agency or utility, as applicable, have
20074	20074	8 executed the contract. For those renewable energy
20075	20075	9 credits subject to procurement through a competitive
20076	20076	10 bid process under the plan or under the initial
20077	20077	11 forward procurements for wind and solar resources
20078	20078	12 described in subparagraph (G) of paragraph (1) of
20079	20079	13 subsection (c) of Section 1-75 of the Illinois Power
20080	20080	14 Agency Act, the Agency shall follow the procurement
20081	20081	15 process specified in the provisions relating to
20082	20082	16 electricity procurement in subsections (e) through (i)
20083	20083	17 of this Section.
20084	20084	18 (iv) An electric utility shall recover its costs
20085	20085	19 associated with the procurement of renewable energy
20086	20086	20 credits under this Section and pursuant to subsection
20087	20087	21 (c-5) of Section 1-75 of the Illinois Power Agency Act
20088	20088	22 through an automatic adjustment clause tariff under
20089	20089	23 subsection (k) or a tariff pursuant to subsection
20090	20090	24 (i-5), as applicable, of Section 16-108 of this Act. A
20091	20091	25 utility shall not be required to advance any payment
20092	20092	26 or pay any amounts under this Section that exceed the
20093	20093
20094	20094
20095	20095
20096	20096
20097	20097
20098	20098	HB3779 - 559 - LRB104 11172 AAS 21254 b
20099	20099
20100	20100
20101	20101	HB3779- 560 -LRB104 11172 AAS 21254 b HB3779 - 560 - LRB104 11172 AAS 21254 b
20102	20102	HB3779 - 560 - LRB104 11172 AAS 21254 b
20103	20103	1 actual amount of revenues collected by the utility
20104	20104	2 under paragraph (6) of subsection (c) of Section 1-75
20105	20105	3 of the Illinois Power Agency Act, subsection (c-5) of
20106	20106	4 Section 1-75 of the Illinois Power Agency Act, and
20107	20107	5 subsection (k) or subsection (i-5), as applicable, of
20108	20108	6 Section 16-108 of this Act, and contracts executed
20109	20109	7 under this Section shall expressly incorporate this
20110	20110	8 limitation.
20111	20111	9 (v) For the public interest, safety, and welfare,
20112	20112	10 the Agency and the Commission may adopt rules to carry
20113	20113	11 out the provisions of this Section on an emergency
20114	20114	12 basis immediately following the effective date of this
20115	20115	13 amendatory Act of the 99th General Assembly.
20116	20116	14 (vi) On or before July 1 of each year, the
20117	20117	15 Commission shall hold an informal hearing for the
20118	20118	16 purpose of receiving comments on the prior year's
20119	20119	17 procurement process and any recommendations for
20120	20120	18 change.
20121	20121	19 (b-5) An electric utility that as of January 1, 2019
20122	20122	20 served more than 300,000 retail customers in this State shall
20123	20123	21 purchase renewable energy credits from new renewable energy
20124	20124	22 facilities constructed at or adjacent to the sites of
20125	20125	23 coal-fueled electric generating facilities in this State in
20126	20126	24 accordance with subsection (c-5) of Section 1-75 of the
20127	20127	25 Illinois Power Agency Act. Except as expressly provided in
20128	20128	26 this Section, the plans and procedures for such procurements
20129	20129
20130	20130
20131	20131
20132	20132
20133	20133
20134	20134	HB3779 - 560 - LRB104 11172 AAS 21254 b
20135	20135
20136	20136
20137	20137	HB3779- 561 -LRB104 11172 AAS 21254 b HB3779 - 561 - LRB104 11172 AAS 21254 b
20138	20138	HB3779 - 561 - LRB104 11172 AAS 21254 b
20139	20139	1 shall not be included in the procurement plans provided for in
20140	20140	2 this Section, but rather shall be conducted and implemented
20141	20141	3 solely in accordance with subsection (c-5) of Section 1-75 of
20142	20142	4 the Illinois Power Agency Act.
20143	20143	5 (b-10) Capacity procurement.
20144	20144	6 (1) Definitions. For purposes of this subsection:
20145	20145	7 "Applicable Local Resource Zone" means the Zone 4
20146	20146	8 Local Resource Zone as set forth in the MISO Business
20147	20147	9 Practices Manual 011 - Resource Adequacy, or any future
20148	20148	10 successor zone for the same geographic space, as
20149	20149	11 designated by MISO governing documents.
20150	20150	12 "Applicable locational deliverability area" means the
20151	20151	13 ComEd Locational Deliverability Area as set forth in the
20152	20152	14 PJM Manual, or any future successor area for the same
20153	20153	15 geographic space, as designated by PJM governing
20154	20154	16 documents.
20155	20155	17 "Electric cooperative" has the meaning given to that
20156	20156	18 term in Section 3-119.
20157	20157	19 "Fixed Resource Adequacy Plan", "Local Clearing
20158	20158	20 Requirement", "Local Resource Zone", "Planning Resource",
20159	20159	21 and "Planning Reserve Margin Requirement" have the
20160	20160	22 meanings given to those terms in the MISO Tariff,
20161	20161	23 including as they may apply to individual Load Serving
20162	20162	24 Entities, as applicable. For avoidance of doubt, these
20163	20163	25 terms shall be interpreted as multiple seasonal values
20164	20164	26 within a given delivery year if MISO's then-prevailing
20165	20165
20166	20166
20167	20167
20168	20168
20169	20169
20170	20170	HB3779 - 561 - LRB104 11172 AAS 21254 b
20171	20171
20172	20172
20173	20173	HB3779- 562 -LRB104 11172 AAS 21254 b HB3779 - 562 - LRB104 11172 AAS 21254 b
20174	20174	HB3779 - 562 - LRB104 11172 AAS 21254 b
20175	20175	1 resource adequacy construct has a seasonal component.
20176	20176	2 "Load Serving Entity" has the meaning given to that
20177	20177	3 term by the regional transmission organization where the
20178	20178	4 entity serves customers, either in the Midcontinent
20179	20179	5 Independent System Operator Tariff or PJM Interconnection,
20180	20180	6 LLC Reliability Assurance Agreement.
20181	20181	7 (c) The provisions of this subsection (c) shall not apply
20182	20182	8 to procurements conducted pursuant to subsection (c-5) of
20183	20183	9 Section 1-75 of the Illinois Power Agency Act. However, the
20184	20184	10 Agency may retain a procurement administrator to assist the
20185	20185	11 Agency in planning and carrying out the procurement events and
20186	20186	12 implementing the other requirements specified in such
20187	20187	13 subsection (c-5) of Section 1-75 of the Illinois Power Agency
20188	20188	14 Act, with the costs incurred by the Agency for the procurement
20189	20189	15 administrator to be recovered through fees charged to
20190	20190	16 applicants for selection to sell and deliver renewable energy
20191	20191	17 credits to electric utilities pursuant to subsection (c-5) of
20192	20192	18 Section 1-75 of the Illinois Power Agency Act. The procurement
20193	20193	19 process set forth in Section 1-75 of the Illinois Power Agency
20194	20194	20 Act and subsection (e) of this Section shall be administered
20195	20195	21 by a procurement administrator and monitored by a procurement
20196	20196	22 monitor.
20197	20197	23 (1) The procurement administrator shall:
20198	20198	24 (i) design the final procurement process in
20199	20199	25 accordance with Section 1-75 of the Illinois Power
20200	20200	26 Agency Act and subsection (e) of this Section
20201	20201
20202	20202
20203	20203
20204	20204
20205	20205
20206	20206	HB3779 - 562 - LRB104 11172 AAS 21254 b
20207	20207
20208	20208
20209	20209	HB3779- 563 -LRB104 11172 AAS 21254 b HB3779 - 563 - LRB104 11172 AAS 21254 b
20210	20210	HB3779 - 563 - LRB104 11172 AAS 21254 b
20211	20211	1 following Commission approval of the procurement plan;
20212	20212	2 (ii) develop benchmarks in accordance with
20213	20213	3 subsection (e)(3) to be used to evaluate bids; these
20214	20214	4 benchmarks shall be submitted to the Commission for
20215	20215	5 review and approval on a confidential basis prior to
20216	20216	6 the procurement event;
20217	20217	7 (iii) serve as the interface between the electric
20218	20218	8 utility and suppliers;
20219	20219	9 (iv) manage the bidder pre-qualification and
20220	20220	10 registration process;
20221	20221	11 (v) obtain the electric utilities' agreement to
20222	20222	12 the final form of all supply contracts and credit
20223	20223	13 collateral agreements;
20224	20224	14 (vi) administer the request for proposals process;
20225	20225	15 (vii) have the discretion to negotiate to
20226	20226	16 determine whether bidders are willing to lower the
20227	20227	17 price of bids that meet the benchmarks approved by the
20228	20228	18 Commission; any post-bid negotiations with bidders
20229	20229	19 shall be limited to price only and shall be completed
20230	20230	20 within 24 hours after opening the sealed bids and
20231	20231	21 shall be conducted in a fair and unbiased manner; in
20232	20232	22 conducting the negotiations, there shall be no
20233	20233	23 disclosure of any information derived from proposals
20234	20234	24 submitted by competing bidders; if information is
20235	20235	25 disclosed to any bidder, it shall be provided to all
20236	20236	26 competing bidders;
20237	20237
20238	20238
20239	20239
20240	20240
20241	20241
20242	20242	HB3779 - 563 - LRB104 11172 AAS 21254 b
20243	20243
20244	20244
20245	20245	HB3779- 564 -LRB104 11172 AAS 21254 b HB3779 - 564 - LRB104 11172 AAS 21254 b
20246	20246	HB3779 - 564 - LRB104 11172 AAS 21254 b
20247	20247	1 (viii) maintain confidentiality of supplier and
20248	20248	2 bidding information in a manner consistent with all
20249	20249	3 applicable laws, rules, regulations, and tariffs;
20250	20250	4 (ix) submit a confidential report to the
20251	20251	5 Commission recommending acceptance or rejection of
20252	20252	6 bids;
20253	20253	7 (x) notify the utility of contract counterparties
20254	20254	8 and contract specifics; and
20255	20255	9 (xi) administer related contingency procurement
20256	20256	10 events.
20257	20257	11 (2) The procurement monitor, who shall be retained by
20258	20258	12 the Commission, shall:
20259	20259	13 (i) monitor interactions among the procurement
20260	20260	14 administrator, suppliers, and utility;
20261	20261	15 (ii) monitor and report to the Commission on the
20262	20262	16 progress of the procurement process;
20263	20263	17 (iii) provide an independent confidential report
20264	20264	18 to the Commission regarding the results of the
20265	20265	19 procurement event;
20266	20266	20 (iv) assess compliance with the procurement plans
20267	20267	21 approved by the Commission for each utility that on
20268	20268	22 December 31, 2005 provided electric service to at
20269	20269	23 least 100,000 customers in Illinois and for each small
20270	20270	24 multi-jurisdictional utility that on December 31, 2005
20271	20271	25 served less than 100,000 customers in Illinois;
20272	20272	26 (v) preserve the confidentiality of supplier and
20273	20273
20274	20274
20275	20275
20276	20276
20277	20277
20278	20278	HB3779 - 564 - LRB104 11172 AAS 21254 b
20279	20279
20280	20280
20281	20281	HB3779- 565 -LRB104 11172 AAS 21254 b HB3779 - 565 - LRB104 11172 AAS 21254 b
20282	20282	HB3779 - 565 - LRB104 11172 AAS 21254 b
20283	20283	1 bidding information in a manner consistent with all
20284	20284	2 applicable laws, rules, regulations, and tariffs;
20285	20285	3 (vi) provide expert advice to the Commission and
20286	20286	4 consult with the procurement administrator regarding
20287	20287	5 issues related to procurement process design, rules,
20288	20288	6 protocols, and policy-related matters; and
20289	20289	7 (vii) consult with the procurement administrator
20290	20290	8 regarding the development and use of benchmark
20291	20291	9 criteria, standard form contracts, credit policies,
20292	20292	10 and bid documents.
20293	20293	11 (d) Except as provided in subsection (j), the planning
20294	20294	12 process shall be conducted as follows:
20295	20295	13 (1) Beginning in 2008, each Illinois utility procuring
20296	20296	14 power pursuant to this Section shall annually provide a
20297	20297	15 range of load forecasts to the Illinois Power Agency by
20298	20298	16 July 15 of each year, or such other date as may be required
20299	20299	17 by the Commission or Agency. The load forecasts shall
20300	20300	18 cover the 5-year procurement planning period for the next
20301	20301	19 procurement plan and shall include hourly data
20302	20302	20 representing a high-load, low-load, and expected-load
20303	20303	21 scenario for the load of those retail customers included
20304	20304	22 in the plan's electric supply service requirements. The
20305	20305	23 utility shall provide supporting data and assumptions for
20306	20306	24 each of the scenarios.
20307	20307	25 (2) Beginning in 2008, the Illinois Power Agency shall
20308	20308	26 prepare a procurement plan by August 15th of each year, or
20309	20309
20310	20310
20311	20311
20312	20312
20313	20313
20314	20314	HB3779 - 565 - LRB104 11172 AAS 21254 b
20315	20315
20316	20316
20317	20317	HB3779- 566 -LRB104 11172 AAS 21254 b HB3779 - 566 - LRB104 11172 AAS 21254 b
20318	20318	HB3779 - 566 - LRB104 11172 AAS 21254 b
20319	20319	1 such other date as may be required by the Commission. The
20320	20320	2 procurement plan shall identify the portfolio of
20321	20321	3 demand-response and power and energy products to be
20322	20322	4 procured. Cost-effective demand-response measures shall be
20323	20323	5 procured as set forth in item (iii) of subsection (b) of
20324	20324	6 this Section. Copies of the procurement plan shall be
20325	20325	7 posted and made publicly available on the Agency's and
20326	20326	8 Commission's websites, and copies shall also be provided
20327	20327	9 to each affected electric utility. An affected utility
20328	20328	10 shall have 30 days following the date of posting to
20329	20329	11 provide comment to the Agency on the procurement plan.
20330	20330	12 Other interested entities also may comment on the
20331	20331	13 procurement plan. All comments submitted to the Agency
20332	20332	14 shall be specific, supported by data or other detailed
20333	20333	15 analyses, and, if objecting to all or a portion of the
20334	20334	16 procurement plan, accompanied by specific alternative
20335	20335	17 wording or proposals. All comments shall be posted on the
20336	20336	18 Agency's and Commission's websites. During this 30-day
20337	20337	19 comment period, the Agency shall hold at least one public
20338	20338	20 hearing within each utility's service area for the purpose
20339	20339	21 of receiving public comment on the procurement plan.
20340	20340	22 Within 14 days following the end of the 30-day review
20341	20341	23 period, the Agency shall revise the procurement plan as
20342	20342	24 necessary based on the comments received and file the
20343	20343	25 procurement plan with the Commission and post the
20344	20344	26 procurement plan on the websites.
20345	20345
20346	20346
20347	20347
20348	20348
20349	20349
20350	20350	HB3779 - 566 - LRB104 11172 AAS 21254 b
20351	20351
20352	20352
20353	20353	HB3779- 567 -LRB104 11172 AAS 21254 b HB3779 - 567 - LRB104 11172 AAS 21254 b
20354	20354	HB3779 - 567 - LRB104 11172 AAS 21254 b
20355	20355	1 (3) Within 5 days after the filing of the procurement
20356	20356	2 plan, any person objecting to the procurement plan shall
20357	20357	3 file an objection with the Commission. Within 10 days
20358	20358	4 after the filing, the Commission shall determine whether a
20359	20359	5 hearing is necessary. The Commission shall enter its order
20360	20360	6 confirming or modifying the procurement plan within 90
20361	20361	7 days after the filing of the procurement plan by the
20362	20362	8 Illinois Power Agency.
20363	20363	9 (4) The Commission shall approve the procurement plan,
20364	20364	10 including expressly the forecast used in the procurement
20365	20365	11 plan, if the Commission determines that it will ensure
20366	20366	12 adequate, reliable, affordable, efficient, and
20367	20367	13 environmentally sustainable electric service at the lowest
20368	20368	14 total cost over time, taking into account any benefits of
20369	20369	15 price stability.
20370	20370	16 (4.5) The Commission shall review the Agency's
20371	20371	17 recommendations for the selection of applicants to enter
20372	20372	18 into long-term contracts for the sale and delivery of
20373	20373	19 renewable energy credits from new renewable energy
20374	20374	20 facilities to be constructed at or adjacent to the sites
20375	20375	21 of coal-fueled electric generating facilities in this
20376	20376	22 State in accordance with the provisions of subsection
20377	20377	23 (c-5) of Section 1-75 of the Illinois Power Agency Act,
20378	20378	24 and shall approve the Agency's recommendations if the
20379	20379	25 Commission determines that the applicants recommended by
20380	20380	26 the Agency for selection, the proposed new renewable
20381	20381
20382	20382
20383	20383
20384	20384
20385	20385
20386	20386	HB3779 - 567 - LRB104 11172 AAS 21254 b
20387	20387
20388	20388
20389	20389	HB3779- 568 -LRB104 11172 AAS 21254 b HB3779 - 568 - LRB104 11172 AAS 21254 b
20390	20390	HB3779 - 568 - LRB104 11172 AAS 21254 b
20391	20391	1 energy facilities to be constructed, the amounts of
20392	20392	2 renewable energy credits to be delivered pursuant to the
20393	20393	3 contracts, and the other terms of the contracts, are
20394	20394	4 consistent with the requirements of subsection (c-5) of
20395	20395	5 Section 1-75 of the Illinois Power Agency Act.
20396	20396	6 (e) The procurement process shall include each of the
20397	20397	7 following components:
20398	20398	8 (1) Solicitation, pre-qualification, and registration
20399	20399	9 of bidders. The procurement administrator shall
20400	20400	10 disseminate information to potential bidders to promote a
20401	20401	11 procurement event, notify potential bidders that the
20402	20402	12 procurement administrator may enter into a post-bid price
20403	20403	13 negotiation with bidders that meet the applicable
20404	20404	14 benchmarks, provide supply requirements, and otherwise
20405	20405	15 explain the competitive procurement process. In addition
20406	20406	16 to such other publication as the procurement administrator
20407	20407	17 determines is appropriate, this information shall be
20408	20408	18 posted on the Illinois Power Agency's and the Commission's
20409	20409	19 websites. The procurement administrator shall also
20410	20410	20 administer the prequalification process, including
20411	20411	21 evaluation of credit worthiness, compliance with
20412	20412	22 procurement rules, and agreement to the standard form
20413	20413	23 contract developed pursuant to paragraph (2) of this
20414	20414	24 subsection (e). The procurement administrator shall then
20415	20415	25 identify and register bidders to participate in the
20416	20416	26 procurement event.
20417	20417
20418	20418
20419	20419
20420	20420
20421	20421
20422	20422	HB3779 - 568 - LRB104 11172 AAS 21254 b
20423	20423
20424	20424
20425	20425	HB3779- 569 -LRB104 11172 AAS 21254 b HB3779 - 569 - LRB104 11172 AAS 21254 b
20426	20426	HB3779 - 569 - LRB104 11172 AAS 21254 b
20427	20427	1 (2) Standard contract forms and credit terms and
20428	20428	2 instruments. The procurement administrator, in
20429	20429	3 consultation with the utilities, the Commission, and other
20430	20430	4 interested parties and subject to Commission oversight,
20431	20431	5 shall develop and provide standard contract forms for the
20432	20432	6 supplier contracts that meet generally accepted industry
20433	20433	7 practices. Standard credit terms and instruments that meet
20434	20434	8 generally accepted industry practices shall be similarly
20435	20435	9 developed. The procurement administrator shall make
20436	20436	10 available to the Commission all written comments it
20437	20437	11 receives on the contract forms, credit terms, or
20438	20438	12 instruments. If the procurement administrator cannot reach
20439	20439	13 agreement with the applicable electric utility as to the
20440	20440	14 contract terms and conditions, the procurement
20441	20441	15 administrator must notify the Commission of any disputed
20442	20442	16 terms and the Commission shall resolve the dispute. The
20443	20443	17 terms of the contracts shall not be subject to negotiation
20444	20444	18 by winning bidders, and the bidders must agree to the
20445	20445	19 terms of the contract in advance so that winning bids are
20446	20446	20 selected solely on the basis of price.
20447	20447	21 (3) Establishment of a market-based price benchmark.
20448	20448	22 As part of the development of the procurement process, the
20449	20449	23 procurement administrator, in consultation with the
20450	20450	24 Commission staff, Agency staff, and the procurement
20451	20451	25 monitor, shall establish benchmarks for evaluating the
20452	20452	26 final prices in the contracts for each of the products
20453	20453
20454	20454
20455	20455
20456	20456
20457	20457
20458	20458	HB3779 - 569 - LRB104 11172 AAS 21254 b
20459	20459
20460	20460
20461	20461	HB3779- 570 -LRB104 11172 AAS 21254 b HB3779 - 570 - LRB104 11172 AAS 21254 b
20462	20462	HB3779 - 570 - LRB104 11172 AAS 21254 b
20463	20463	1 that will be procured through the procurement process. The
20464	20464	2 benchmarks shall be based on price data for similar
20465	20465	3 products for the same delivery period and same delivery
20466	20466	4 hub, or other delivery hubs after adjusting for that
20467	20467	5 difference. The price benchmarks may also be adjusted to
20468	20468	6 take into account differences between the information
20469	20469	7 reflected in the underlying data sources and the specific
20470	20470	8 products and procurement process being used to procure
20471	20471	9 power for the Illinois utilities. The benchmarks shall be
20472	20472	10 confidential but shall be provided to, and will be subject
20473	20473	11 to Commission review and approval, prior to a procurement
20474	20474	12 event.
20475	20475	13 (4) Request for proposals competitive procurement
20476	20476	14 process. The procurement administrator shall design and
20477	20477	15 issue a request for proposals to supply electricity in
20478	20478	16 accordance with each utility's procurement plan, as
20479	20479	17 approved by the Commission. The request for proposals
20480	20480	18 shall set forth a procedure for sealed, binding commitment
20481	20481	19 bidding with pay-as-bid settlement, and provision for
20482	20482	20 selection of bids on the basis of price.
20483	20483	21 (5) A plan for implementing contingencies in the event
20484	20484	22 of supplier default or failure of the procurement process
20485	20485	23 to fully meet the expected load requirement due to
20486	20486	24 insufficient supplier participation, Commission rejection
20487	20487	25 of results, or any other cause.
20488	20488	26 (i) Event of supplier default: In the event of
20489	20489
20490	20490
20491	20491
20492	20492
20493	20493
20494	20494	HB3779 - 570 - LRB104 11172 AAS 21254 b
20495	20495
20496	20496
20497	20497	HB3779- 571 -LRB104 11172 AAS 21254 b HB3779 - 571 - LRB104 11172 AAS 21254 b
20498	20498	HB3779 - 571 - LRB104 11172 AAS 21254 b
20499	20499	1 supplier default, the utility shall review the
20500	20500	2 contract of the defaulting supplier to determine if
20501	20501	3 the amount of supply is 200 megawatts or greater, and
20502	20502	4 if there are more than 60 days remaining of the
20503	20503	5 contract term. If both of these conditions are met,
20504	20504	6 and the default results in termination of the
20505	20505	7 contract, the utility shall immediately notify the
20506	20506	8 Illinois Power Agency that a request for proposals
20507	20507	9 must be issued to procure replacement power, and the
20508	20508	10 procurement administrator shall run an additional
20509	20509	11 procurement event. If the contracted supply of the
20510	20510	12 defaulting supplier is less than 200 megawatts or
20511	20511	13 there are less than 60 days remaining of the contract
20512	20512	14 term, the utility shall procure power and energy from
20513	20513	15 the applicable regional transmission organization
20514	20514	16 market, including ancillary services, capacity, and
20515	20515	17 day-ahead or real time energy, or both, for the
20516	20516	18 duration of the contract term to replace the
20517	20517	19 contracted supply; provided, however, that if a needed
20518	20518	20 product is not available through the regional
20519	20519	21 transmission organization market it shall be purchased
20520	20520	22 from the wholesale market.
20521	20521	23 (ii) Failure of the procurement process to fully
20522	20522	24 meet the expected load requirement: If the procurement
20523	20523	25 process fails to fully meet the expected load
20524	20524	26 requirement due to insufficient supplier participation
20525	20525
20526	20526
20527	20527
20528	20528
20529	20529
20530	20530	HB3779 - 571 - LRB104 11172 AAS 21254 b
20531	20531
20532	20532
20533	20533	HB3779- 572 -LRB104 11172 AAS 21254 b HB3779 - 572 - LRB104 11172 AAS 21254 b
20534	20534	HB3779 - 572 - LRB104 11172 AAS 21254 b
20535	20535	1 or due to a Commission rejection of the procurement
20536	20536	2 results, the procurement administrator, the
20537	20537	3 procurement monitor, and the Commission staff shall
20538	20538	4 meet within 10 days to analyze potential causes of low
20539	20539	5 supplier interest or causes for the Commission
20540	20540	6 decision. If changes are identified that would likely
20541	20541	7 result in increased supplier participation, or that
20542	20542	8 would address concerns causing the Commission to
20543	20543	9 reject the results of the prior procurement event, the
20544	20544	10 procurement administrator may implement those changes
20545	20545	11 and rerun the request for proposals process according
20546	20546	12 to a schedule determined by those parties and
20547	20547	13 consistent with Section 1-75 of the Illinois Power
20548	20548	14 Agency Act and this subsection. In any event, a new
20549	20549	15 request for proposals process shall be implemented by
20550	20550	16 the procurement administrator within 90 days after the
20551	20551	17 determination that the procurement process has failed
20552	20552	18 to fully meet the expected load requirement.
20553	20553	19 (iii) In all cases where there is insufficient
20554	20554	20 supply provided under contracts awarded through the
20555	20555	21 procurement process to fully meet the electric
20556	20556	22 utility's load requirement, the utility shall meet the
20557	20557	23 load requirement by procuring power and energy from
20558	20558	24 the applicable regional transmission organization
20559	20559	25 market, including ancillary services, capacity, and
20560	20560	26 day-ahead or real time energy, or both; provided,
20561	20561
20562	20562
20563	20563
20564	20564
20565	20565
20566	20566	HB3779 - 572 - LRB104 11172 AAS 21254 b
20567	20567
20568	20568
20569	20569	HB3779- 573 -LRB104 11172 AAS 21254 b HB3779 - 573 - LRB104 11172 AAS 21254 b
20570	20570	HB3779 - 573 - LRB104 11172 AAS 21254 b
20571	20571	1 however, that if a needed product is not available
20572	20572	2 through the regional transmission organization market
20573	20573	3 it shall be purchased from the wholesale market.
20574	20574	4 (6) The procurement processes described in this
20575	20575	5 subsection and in subsection (c-5) of Section 1-75 of the
20576	20576	6 Illinois Power Agency Act are exempt from the requirements
20577	20577	7 of the Illinois Procurement Code, pursuant to Section
20578	20578	8 20-10 of that Code.
20579	20579	9 (f) Within 2 business days after opening the sealed bids,
20580	20580	10 the procurement administrator shall submit a confidential
20581	20581	11 report to the Commission. The report shall contain the results
20582	20582	12 of the bidding for each of the products along with the
20583	20583	13 procurement administrator's recommendation for the acceptance
20584	20584	14 and rejection of bids based on the price benchmark criteria
20585	20585	15 and other factors observed in the process. The procurement
20586	20586	16 monitor also shall submit a confidential report to the
20587	20587	17 Commission within 2 business days after opening the sealed
20588	20588	18 bids. The report shall contain the procurement monitor's
20589	20589	19 assessment of bidder behavior in the process as well as an
20590	20590	20 assessment of the procurement administrator's compliance with
20591	20591	21 the procurement process and rules. The Commission shall review
20592	20592	22 the confidential reports submitted by the procurement
20593	20593	23 administrator and procurement monitor, and shall accept or
20594	20594	24 reject the recommendations of the procurement administrator
20595	20595	25 within 2 business days after receipt of the reports.
20596	20596	26 (g) Within 3 business days after the Commission decision
20597	20597
20598	20598
20599	20599
20600	20600
20601	20601
20602	20602	HB3779 - 573 - LRB104 11172 AAS 21254 b
20603	20603
20604	20604
20605	20605	HB3779- 574 -LRB104 11172 AAS 21254 b HB3779 - 574 - LRB104 11172 AAS 21254 b
20606	20606	HB3779 - 574 - LRB104 11172 AAS 21254 b
20607	20607	1 approving the results of a procurement event, the utility
20608	20608	2 shall enter into binding contractual arrangements with the
20609	20609	3 winning suppliers using the standard form contracts; except
20610	20610	4 that the utility shall not be required either directly or
20611	20611	5 indirectly to execute the contracts if a tariff that is
20612	20612	6 consistent with subsection (l) of this Section has not been
20613	20613	7 approved and placed into effect for that utility.
20614	20614	8 (h) For the procurement of standard wholesale products,
20615	20615	9 the names of the successful bidders and the load weighted
20616	20616	10 average of the winning bid prices for each contract type and
20617	20617	11 for each contract term shall be made available to the public at
20618	20618	12 the time of Commission approval of a procurement event. For
20619	20619	13 procurements conducted to meet the requirements of subsection
20620	20620	14 (b) of Section 1-56 or subsection (c) of Section 1-75 of the
20621	20621	15 Illinois Power Agency Act governed by the provisions of this
20622	20622	16 Section, the address and nameplate capacity of the new
20623	20623	17 renewable energy generating facility proposed by a winning
20624	20624	18 bidder shall also be made available to the public at the time
20625	20625	19 of Commission approval of a procurement event, along with the
20626	20626	20 business address and contact information for any winning
20627	20627	21 bidder. An estimate or approximation of the nameplate capacity
20628	20628	22 of the new renewable energy generating facility may be
20629	20629	23 disclosed if necessary to protect the confidentiality of
20630	20630	24 individual bid prices.
20631	20631	25 The Commission, the procurement monitor, the procurement
20632	20632	26 administrator, the Illinois Power Agency, and all participants
20633	20633
20634	20634
20635	20635
20636	20636
20637	20637
20638	20638	HB3779 - 574 - LRB104 11172 AAS 21254 b
20639	20639
20640	20640
20641	20641	HB3779- 575 -LRB104 11172 AAS 21254 b HB3779 - 575 - LRB104 11172 AAS 21254 b
20642	20642	HB3779 - 575 - LRB104 11172 AAS 21254 b
20643	20643	1 in the procurement process shall maintain the confidentiality
20644	20644	2 of all other supplier and bidding information in a manner
20645	20645	3 consistent with all applicable laws, rules, regulations, and
20646	20646	4 tariffs. Confidential information, including the confidential
20647	20647	5 reports submitted by the procurement administrator and
20648	20648	6 procurement monitor pursuant to subsection (f) of this
20649	20649	7 Section, shall not be made publicly available and shall not be
20650	20650	8 discoverable by any party in any proceeding, absent a
20651	20651	9 compelling demonstration of need, nor shall those reports be
20652	20652	10 admissible in any proceeding other than one for law
20653	20653	11 enforcement purposes.
20654	20654	12 (i) Within 2 business days after a Commission decision
20655	20655	13 approving the results of a procurement event or such other
20656	20656	14 date as may be required by the Commission from time to time,
20657	20657	15 the utility shall file for informational purposes with the
20658	20658	16 Commission its actual or estimated retail supply charges, as
20659	20659	17 applicable, by customer supply group reflecting the costs
20660	20660	18 associated with the procurement and computed in accordance
20661	20661	19 with the tariffs filed pursuant to subsection (l) of this
20662	20662	20 Section and approved by the Commission.
20663	20663	21 (j) Within 60 days following August 28, 2007 (the
20664	20664	22 effective date of Public Act 95-481), each electric utility
20665	20665	23 that on December 31, 2005 provided electric service to at
20666	20666	24 least 100,000 customers in Illinois shall prepare and file
20667	20667	25 with the Commission an initial procurement plan, which shall
20668	20668	26 conform in all material respects to the requirements of the
20669	20669
20670	20670
20671	20671
20672	20672
20673	20673
20674	20674	HB3779 - 575 - LRB104 11172 AAS 21254 b
20675	20675
20676	20676
20677	20677	HB3779- 576 -LRB104 11172 AAS 21254 b HB3779 - 576 - LRB104 11172 AAS 21254 b
20678	20678	HB3779 - 576 - LRB104 11172 AAS 21254 b
20679	20679	1 procurement plan set forth in subsection (b); provided,
20680	20680	2 however, that the Illinois Power Agency Act shall not apply to
20681	20681	3 the initial procurement plan prepared pursuant to this
20682	20682	4 subsection. The initial procurement plan shall identify the
20683	20683	5 portfolio of power and energy products to be procured and
20684	20684	6 delivered for the period June 2008 through May 2009, and shall
20685	20685	7 identify the proposed procurement administrator, who shall
20686	20686	8 have the same experience and expertise as is required of a
20687	20687	9 procurement administrator hired pursuant to Section 1-75 of
20688	20688	10 the Illinois Power Agency Act. Copies of the procurement plan
20689	20689	11 shall be posted and made publicly available on the
20690	20690	12 Commission's website. The initial procurement plan may include
20691	20691	13 contracts for renewable resources that extend beyond May 2009.
20692	20692	14 (i) Within 14 days following filing of the initial
20693	20693	15 procurement plan, any person may file a detailed objection
20694	20694	16 with the Commission contesting the procurement plan
20695	20695	17 submitted by the electric utility. All objections to the
20696	20696	18 electric utility's plan shall be specific, supported by
20697	20697	19 data or other detailed analyses. The electric utility may
20698	20698	20 file a response to any objections to its procurement plan
20699	20699	21 within 7 days after the date objections are due to be
20700	20700	22 filed. Within 7 days after the date the utility's response
20701	20701	23 is due, the Commission shall determine whether a hearing
20702	20702	24 is necessary. If it determines that a hearing is
20703	20703	25 necessary, it shall require the hearing to be completed
20704	20704	26 and issue an order on the procurement plan within 60 days
20705	20705
20706	20706
20707	20707
20708	20708
20709	20709
20710	20710	HB3779 - 576 - LRB104 11172 AAS 21254 b
20711	20711
20712	20712
20713	20713	HB3779- 577 -LRB104 11172 AAS 21254 b HB3779 - 577 - LRB104 11172 AAS 21254 b
20714	20714	HB3779 - 577 - LRB104 11172 AAS 21254 b
20715	20715	1 after the filing of the procurement plan by the electric
20716	20716	2 utility.
20717	20717	3 (ii) The order shall approve or modify the procurement
20718	20718	4 plan, approve an independent procurement administrator,
20719	20719	5 and approve or modify the electric utility's tariffs that
20720	20720	6 are proposed with the initial procurement plan. The
20721	20721	7 Commission shall approve the procurement plan if the
20722	20722	8 Commission determines that it will ensure adequate,
20723	20723	9 reliable, affordable, efficient, and environmentally
20724	20724	10 sustainable electric service at the lowest total cost over
20725	20725	11 time, taking into account any benefits of price stability.
20726	20726	12 (k) (Blank).
20727	20727	13 (k-5) (Blank).
20728	20728	14 (l) An electric utility shall recover its costs incurred
20729	20729	15 under this Section and subsection (c-5) of Section 1-75 of the
20730	20730	16 Illinois Power Agency Act, including, but not limited to, the
20731	20731	17 costs of procuring power and energy demand-response resources
20732	20732	18 under this Section and its costs for purchasing renewable
20733	20733	19 energy credits pursuant to subsection (c-5) of Section 1-75 of
20734	20734	20 the Illinois Power Agency Act. The utility shall file with the
20735	20735	21 initial procurement plan its proposed tariffs through which
20736	20736	22 its costs of procuring power that are incurred pursuant to a
20737	20737	23 Commission-approved procurement plan and those other costs
20738	20738	24 identified in this subsection (l), will be recovered. The
20739	20739	25 tariffs shall include a formula rate or charge designed to
20740	20740	26 pass through both the costs incurred by the utility in
20741	20741
20742	20742
20743	20743
20744	20744
20745	20745
20746	20746	HB3779 - 577 - LRB104 11172 AAS 21254 b
20747	20747
20748	20748
20749	20749	HB3779- 578 -LRB104 11172 AAS 21254 b HB3779 - 578 - LRB104 11172 AAS 21254 b
20750	20750	HB3779 - 578 - LRB104 11172 AAS 21254 b
20751	20751	1 procuring a supply of electric power and energy for the
20752	20752	2 applicable customer classes with no mark-up or return on the
20753	20753	3 price paid by the utility for that supply, plus any just and
20754	20754	4 reasonable costs that the utility incurs in arranging and
20755	20755	5 providing for the supply of electric power and energy. The
20756	20756	6 formula rate or charge shall also contain provisions that
20757	20757	7 ensure that its application does not result in over or under
20758	20758	8 recovery due to changes in customer usage and demand patterns,
20759	20759	9 and that provide for the correction, on at least an annual
20760	20760	10 basis, of any accounting errors that may occur. A utility
20761	20761	11 shall recover through the tariff all reasonable costs incurred
20762	20762	12 to implement or comply with any procurement plan that is
20763	20763	13 developed and put into effect pursuant to Section 1-75 of the
20764	20764	14 Illinois Power Agency Act and this Section, and for the
20765	20765	15 procurement of renewable energy credits pursuant to subsection
20766	20766	16 (c-5) of Section 1-75 of the Illinois Power Agency Act,
20767	20767	17 including any fees assessed by the Illinois Power Agency,
20768	20768	18 costs associated with load balancing, and contingency plan
20769	20769	19 costs. The electric utility shall also recover its full costs
20770	20770	20 of procuring electric supply for which it contracted before
20771	20771	21 the effective date of this Section in conjunction with the
20772	20772	22 provision of full requirements service under fixed-price
20773	20773	23 bundled service tariffs subsequent to December 31, 2006. All
20774	20774	24 such costs shall be deemed to have been prudently incurred.
20775	20775	25 The pass-through tariffs that are filed and approved pursuant
20776	20776	26 to this Section shall not be subject to review under, or in any
20777	20777
20778	20778
20779	20779
20780	20780
20781	20781
20782	20782	HB3779 - 578 - LRB104 11172 AAS 21254 b
20783	20783
20784	20784
20785	20785	HB3779- 579 -LRB104 11172 AAS 21254 b HB3779 - 579 - LRB104 11172 AAS 21254 b
20786	20786	HB3779 - 579 - LRB104 11172 AAS 21254 b
20787	20787	1 way limited by, Section 16-111(i) of this Act. All of the costs
20788	20788	2 incurred by the electric utility associated with the purchase
20789	20789	3 of zero emission credits in accordance with subsection (d-5)
20790	20790	4 of Section 1-75 of the Illinois Power Agency Act, all costs
20791	20791	5 incurred by the electric utility associated with the purchase
20792	20792	6 of carbon mitigation credits in accordance with subsection
20793	20793	7 (d-10) of Section 1-75 of the Illinois Power Agency Act, and,
20794	20794	8 beginning June 1, 2017, all of the costs incurred by the
20795	20795	9 electric utility associated with the purchase of renewable
20796	20796	10 energy resources in accordance with Sections 1-56 and 1-75 of
20797	20797	11 the Illinois Power Agency Act, and all of the costs incurred by
20798	20798	12 the electric utility in purchasing renewable energy credits in
20799	20799	13 accordance with subsection (c-5) of Section 1-75 of the
20800	20800	14 Illinois Power Agency Act, shall be recovered through the
20801	20801	15 electric utility's tariffed charges applicable to all of its
20802	20802	16 retail customers, as specified in subsection (k) or subsection
20803	20803	17 (i-5), as applicable, of Section 16-108 of this Act, and shall
20804	20804	18 not be recovered through the electric utility's tariffed
20805	20805	19 charges for electric power and energy supply to its eligible
20806	20806	20 retail customers.
20807	20807	21 (m) The Commission has the authority to adopt rules to
20808	20808	22 carry out the provisions of this Section. For the public
20809	20809	23 interest, safety, and welfare, the Commission also has
20810	20810	24 authority to adopt rules to carry out the provisions of this
20811	20811	25 Section on an emergency basis immediately following August 28,
20812	20812	26 2007 (the effective date of Public Act 95-481).
20813	20813
20814	20814
20815	20815
20816	20816
20817	20817
20818	20818	HB3779 - 579 - LRB104 11172 AAS 21254 b
20819	20819
20820	20820
20821	20821	HB3779- 580 -LRB104 11172 AAS 21254 b HB3779 - 580 - LRB104 11172 AAS 21254 b
20822	20822	HB3779 - 580 - LRB104 11172 AAS 21254 b
20823	20823	1 (n) Notwithstanding any other provision of this Act, any
20824	20824	2 affiliated electric utilities that submit a single procurement
20825	20825	3 plan covering their combined needs may procure for those
20826	20826	4 combined needs in conjunction with that plan, and may enter
20827	20827	5 jointly into power supply contracts, purchases, and other
20828	20828	6 procurement arrangements, and allocate capacity and energy and
20829	20829	7 cost responsibility therefor among themselves in proportion to
20830	20830	8 their requirements.
20831	20831	9 (o) On or before June 1 of each year, the Commission shall
20832	20832	10 hold an informal hearing for the purpose of receiving comments
20833	20833	11 on the prior year's procurement process and any
20834	20834	12 recommendations for change.
20835	20835	13 (p) An electric utility subject to this Section may
20836	20836	14 propose to invest, lease, own, or operate an electric
20837	20837	15 generation facility as part of its procurement plan, provided
20838	20838	16 the utility demonstrates that such facility is the least-cost
20839	20839	17 option to provide electric service to those retail customers
20840	20840	18 included in the plan's electric supply service requirements.
20841	20841	19 If the facility is shown to be the least-cost option and is
20842	20842	20 included in a procurement plan prepared in accordance with
20843	20843	21 Section 1-75 of the Illinois Power Agency Act and this
20844	20844	22 Section, then the electric utility shall make a filing
20845	20845	23 pursuant to Section 8-406 of this Act, and may request of the
20846	20846	24 Commission any statutory relief required thereunder. If the
20847	20847	25 Commission grants all of the necessary approvals for the
20848	20848	26 proposed facility, such supply shall thereafter be considered
20849	20849
20850	20850
20851	20851
20852	20852
20853	20853
20854	20854	HB3779 - 580 - LRB104 11172 AAS 21254 b
20855	20855
20856	20856
20857	20857	HB3779- 581 -LRB104 11172 AAS 21254 b HB3779 - 581 - LRB104 11172 AAS 21254 b
20858	20858	HB3779 - 581 - LRB104 11172 AAS 21254 b
20859	20859	1 as a pre-existing contract under subsection (b) of this
20860	20860	2 Section. The Commission shall in any order approving a
20861	20861	3 proposal under this subsection specify how the utility will
20862	20862	4 recover the prudently incurred costs of investing in, leasing,
20863	20863	5 owning, or operating such generation facility through just and
20864	20864	6 reasonable rates charged to those retail customers included in
20865	20865	7 the plan's electric supply service requirements. Cost recovery
20866	20866	8 for facilities included in the utility's procurement plan
20867	20867	9 pursuant to this subsection shall not be subject to review
20868	20868	10 under or in any way limited by the provisions of Section
20869	20869	11 16-111(i) of this Act. Nothing in this Section is intended to
20870	20870	12 prohibit a utility from filing for a fuel adjustment clause as
20871	20871	13 is otherwise permitted under Section 9-220 of this Act.
20872	20872	14 (q) If the Illinois Power Agency filed with the
20873	20873	15 Commission, under Section 16-111.5 of this Act, its proposed
20874	20874	16 procurement plan for the period commencing June 1, 2017, and
20875	20875	17 the Commission has not yet entered its final order approving
20876	20876	18 the plan on or before the effective date of this amendatory Act
20877	20877	19 of the 99th General Assembly, then the Illinois Power Agency
20878	20878	20 shall file a notice of withdrawal with the Commission, after
20879	20879	21 the effective date of this amendatory Act of the 99th General
20880	20880	22 Assembly, to withdraw the proposed procurement of renewable
20881	20881	23 energy resources to be approved under the plan, other than the
20882	20882	24 procurement of renewable energy credits from distributed
20883	20883	25 renewable energy generation devices using funds previously
20884	20884	26 collected from electric utilities' retail customers that take
20885	20885
20886	20886
20887	20887
20888	20888
20889	20889
20890	20890	HB3779 - 581 - LRB104 11172 AAS 21254 b
20891	20891
20892	20892
20893	20893	HB3779- 582 -LRB104 11172 AAS 21254 b HB3779 - 582 - LRB104 11172 AAS 21254 b
20894	20894	HB3779 - 582 - LRB104 11172 AAS 21254 b
20895	20895	1 service pursuant to electric utilities' hourly pricing tariff
20896	20896	2 or tariffs and, for an electric utility that serves less than
20897	20897	3 100,000 retail customers in the State, other than the
20898	20898	4 procurement of renewable energy credits from distributed
20899	20899	5 renewable energy generation devices. Upon receipt of the
20900	20900	6 notice, the Commission shall enter an order that approves the
20901	20901	7 withdrawal of the proposed procurement of renewable energy
20902	20902	8 resources from the plan. The initially proposed procurement of
20903	20903	9 renewable energy resources shall not be approved or be the
20904	20904	10 subject of any further hearing, investigation, proceeding, or
20905	20905	11 order of any kind.
20906	20906	12 This amendatory Act of the 99th General Assembly preempts
20907	20907	13 and supersedes any order entered by the Commission that
20908	20908	14 approved the Illinois Power Agency's procurement plan for the
20909	20909	15 period commencing June 1, 2017, to the extent it is
20910	20910	16 inconsistent with the provisions of this amendatory Act of the
20911	20911	17 99th General Assembly. To the extent any previously entered
20912	20912	18 order approved the procurement of renewable energy resources,
20913	20913	19 the portion of that order approving the procurement shall be
20914	20914	20 void, other than the procurement of renewable energy credits
20915	20915	21 from distributed renewable energy generation devices using
20916	20916	22 funds previously collected from electric utilities' retail
20917	20917	23 customers that take service under electric utilities' hourly
20918	20918	24 pricing tariff or tariffs and, for an electric utility that
20919	20919	25 serves less than 100,000 retail customers in the State, other
20920	20920	26 than the procurement of renewable energy credits for
20921	20921
20922	20922
20923	20923
20924	20924
20925	20925
20926	20926	HB3779 - 582 - LRB104 11172 AAS 21254 b
20927	20927
20928	20928
20929	20929	HB3779- 583 -LRB104 11172 AAS 21254 b HB3779 - 583 - LRB104 11172 AAS 21254 b
20930	20930	HB3779 - 583 - LRB104 11172 AAS 21254 b
20931	20931	1 distributed renewable energy generation devices.
20932	20932	2 (Source: P.A. 102-662, eff. 9-15-21.)
20933	20933	3 (220 ILCS 5/16-115A)
20934	20934	4 Sec. 16-115A. Obligations of alternative retail electric
20935	20935	5 suppliers.
20936	20936	6 (a) An alternative retail electric supplier:
20937	20937	7 (i) shall comply with the requirements imposed on
20938	20938	8 public utilities by Sections 8-201 through 8-207, 8-301,
20939	20939	9 8-505 and 8-507 of this Act, to the extent that these
20940	20940	10 Sections have application to the services being offered by
20941	20941	11 the alternative retail electric supplier;
20942	20942	12 (ii) shall continue to comply with the requirements
20943	20943	13 for certification stated in subsection (d) of Section
20944	20944	14 16-115;
20945	20945	15 (iii) by May 31, 2020 and every June 30 thereafter,
20946	20946	16 shall submit to the Commission and the Office of the
20947	20947	17 Attorney General the rates the retail electric supplier
20948	20948	18 charged to residential customers in the prior year,
20949	20949	19 including each distinct rate charged and whether the rate
20950	20950	20 was a fixed or variable rate, the basis for the variable
20951	20951	21 rate, and any fees charged in addition to the supply rate,
20952	20952	22 including monthly fees, flat fees, or other service
20953	20953	23 charges; and
20954	20954	24 (iv) shall make publicly available on its website,
20955	20955	25 without the need for a customer login, rate information
20956	20956
20957	20957
20958	20958
20959	20959
20960	20960
20961	20961	HB3779 - 583 - LRB104 11172 AAS 21254 b
20962	20962
20963	20963
20964	20964	HB3779- 584 -LRB104 11172 AAS 21254 b HB3779 - 584 - LRB104 11172 AAS 21254 b
20965	20965	HB3779 - 584 - LRB104 11172 AAS 21254 b
20966	20966	1 for all of its variable, time-of-use, and fixed rate
20967	20967	2 contracts currently available to residential customers,
20968	20968	3 including, but not limited to, fixed monthly charges,
20969	20969	4 early termination fees, and kilowatt-hour charges; and
20970	20970	5 (v) shall retire all renewable energy credits, as
20971	20971	6 defined in Section 1-10 of the Illinois Power Agency Act,
20972	20972	7 and any other environmental attributes of the energy
20973	20973	8 supply procured from renewable energy resources in
20974	20974	9 compliance with subsection (h) of this Section.
20975	20975	10 (b) An alternative retail electric supplier shall obtain
20976	20976	11 verifiable authorization from a customer, in a form or manner
20977	20977	12 approved by the Commission consistent with Section 2EE of the
20978	20978	13 Consumer Fraud and Deceptive Business Practices Act, before
20979	20979	14 the customer is switched from another supplier.
20980	20980	15 (c) No alternative retail electric supplier, or electric
20981	20981	16 utility other than the electric utility in whose service area
20982	20982	17 a customer is located, shall (i) enter into or employ any
20983	20983	18 arrangements which have the effect of preventing a retail
20984	20984	19 customer with a maximum electrical demand of less than one
20985	20985	20 megawatt from having access to the services of the electric
20986	20986	21 utility in whose service area the customer is located or (ii)
20987	20987	22 charge retail customers for such access. This subsection shall
20988	20988	23 not be construed to prevent an arms-length agreement between a
20989	20989	24 supplier and a retail customer that sets a term of service,
20990	20990	25 notice period for terminating service and provisions governing
20991	20991	26 early termination through a tariff or contract as allowed by
20992	20992
20993	20993
20994	20994
20995	20995
20996	20996
20997	20997	HB3779 - 584 - LRB104 11172 AAS 21254 b
20998	20998
20999	20999
21000	21000	HB3779- 585 -LRB104 11172 AAS 21254 b HB3779 - 585 - LRB104 11172 AAS 21254 b
21001	21001	HB3779 - 585 - LRB104 11172 AAS 21254 b
21002	21002	1 Section 16-119.
21003	21003	2 (d) An alternative retail electric supplier that is
21004	21004	3 certified to serve residential or small commercial retail
21005	21005	4 customers shall not:
21006	21006	5 (1) deny service to a customer or group of customers
21007	21007	6 nor establish any differences as to prices, terms,
21008	21008	7 conditions, services, products, facilities, or in any
21009	21009	8 other respect, whereby such denial or differences are
21010	21010	9 based upon race, gender or income, except as provided in
21011	21011	10 Section 16-115E.
21012	21012	11 (2) deny service to a customer or group of customers
21013	21013	12 based on locality nor establish any unreasonable
21014	21014	13 difference as to prices, terms, conditions, services,
21015	21015	14 products, or facilities as between localities.
21016	21016	15 (3) warrant that it has a residential customer or
21017	21017	16 small commercial retail customer's express consent
21018	21018	17 agreement to access interval data as described in
21019	21019	18 subsection (b) of Section 16-122, unless the alternative
21020	21020	19 retail electric supplier has:
21021	21021	20 (A) disclosed to the consumer at the outset of the
21022	21022	21 offer that the alternative retail electric supplier
21023	21023	22 will access the consumer's interval data from the
21024	21024	23 consumer's utility with the consumer's express
21025	21025	24 agreement and the consumer's option to refuse to
21026	21026	25 provide express agreement to access the consumer's
21027	21027	26 interval data; and
21028	21028
21029	21029
21030	21030
21031	21031
21032	21032
21033	21033	HB3779 - 585 - LRB104 11172 AAS 21254 b
21034	21034
21035	21035
21036	21036	HB3779- 586 -LRB104 11172 AAS 21254 b HB3779 - 586 - LRB104 11172 AAS 21254 b
21037	21037	HB3779 - 586 - LRB104 11172 AAS 21254 b
21038	21038	1 (B) obtained the consumer's express agreement for
21039	21039	2 the alternative retail electric supplier to access the
21040	21040	3 consumer's interval data from the consumer's utility
21041	21041	4 in a separate letter of agency, a distinct response to
21042	21042	5 a third-party verification, or as a separate
21043	21043	6 affirmative consent during a recorded enrollment
21044	21044	7 initiated by the consumer. The disclosure by the
21045	21045	8 alternative retail electric supplier to the consumer
21046	21046	9 in this Section shall be conducted in, translated
21047	21047	10 into, and provided in a language in which the consumer
21048	21048	11 subject to the disclosure is able to understand and
21049	21049	12 communicate.
21050	21050	13 (4) release, sell, license, or otherwise disclose any
21051	21051	14 customer interval data obtained under Section 16-122 to
21052	21052	15 any third person except as provided for in Section 16-122
21053	21053	16 and paragraphs (1) through (4) of subsection (d-5) of
21054	21054	17 Section 2EE of the Consumer Fraud and Deceptive Business
21055	21055	18 Practices Act.
21056	21056	19 (e) An alternative retail electric supplier shall comply
21057	21057	20 with the following requirements with respect to the marketing,
21058	21058	21 offering and provision of products or services to residential
21059	21059	22 and small commercial retail customers:
21060	21060	23 (i) All marketing materials, including, but not
21061	21061	24 limited to, electronic marketing materials, in-person
21062	21062	25 solicitations, and telephone solicitations, shall contain
21063	21063	26 information that adequately discloses the prices, terms,
21064	21064
21065	21065
21066	21066
21067	21067
21068	21068
21069	21069	HB3779 - 586 - LRB104 11172 AAS 21254 b
21070	21070
21071	21071
21072	21072	HB3779- 587 -LRB104 11172 AAS 21254 b HB3779 - 587 - LRB104 11172 AAS 21254 b
21073	21073	HB3779 - 587 - LRB104 11172 AAS 21254 b
21074	21074	1 and conditions of the products or services that the
21075	21075	2 alternative retail electric supplier is offering or
21076	21076	3 selling to the customer and shall disclose the current
21077	21077	4 utility electric supply price to compare applicable at the
21078	21078	5 time the alternative retail electric supplier is offering
21079	21079	6 or selling the products or services to the customer and
21080	21080	7 shall disclose the date on which the utility electric
21081	21081	8 supply price to compare became effective and the date on
21082	21082	9 which it will expire. The utility electric supply price to
21083	21083	10 compare shall be the sum of the electric supply charge and
21084	21084	11 the transmission services charge and shall not include the
21085	21085	12 purchased electricity adjustment. The disclosure shall
21086	21086	13 include a statement that the price to compare does not
21087	21087	14 include the purchased electricity adjustment, and, if
21088	21088	15 applicable, the range of the purchased electricity
21089	21089	16 adjustment. All marketing materials, including, but not
21090	21090	17 limited to, electronic marketing materials, in-person
21091	21091	18 solicitations, and telephone solicitations, shall include
21092	21092	19 the following statement:
21093	21093	20 "(Name of the alternative retail electric
21094	21094	21 supplier) is not the same entity as your electric
21095	21095	22 delivery company. You are not required to enroll with
21096	21096	23 (name of alternative retail electric supplier).
21097	21097	24 Beginning on (effective date), the electric supply
21098	21098	25 price to compare is (price in cents per kilowatt
21099	21099	26 hour). The electric utility electric supply price will
21100	21100
21101	21101
21102	21102
21103	21103
21104	21104
21105	21105	HB3779 - 587 - LRB104 11172 AAS 21254 b
21106	21106
21107	21107
21108	21108	HB3779- 588 -LRB104 11172 AAS 21254 b HB3779 - 588 - LRB104 11172 AAS 21254 b
21109	21109	HB3779 - 588 - LRB104 11172 AAS 21254 b
21110	21110	1 expire on (expiration date). The utility electric
21111	21111	2 supply price to compare does not include the purchased
21112	21112	3 electricity adjustment factor. For more information go
21113	21113	4 to the Illinois Commerce Commission's free website at
21114	21114	5 www.pluginillinois.org.".
21115	21115	6 If applicable, the statement shall also include the
21116	21116	7 following statement:
21117	21117	8 "The purchased electricity adjustment factor may
21118	21118	9 range between +.5 cents and -.5 cents per kilowatt
21119	21119	10 hour.".
21120	21120	11 This paragraph (i) does not apply to goodwill or
21121	21121	12 institutional advertising.
21122	21122	13 (ii) Before any customer is switched from another
21123	21123	14 supplier, the alternative retail electric supplier shall
21124	21124	15 give the customer written information that adequately
21125	21125	16 discloses, in plain language, the prices, terms and
21126	21126	17 conditions of the products and services being offered and
21127	21127	18 sold to the customer. This written information shall be
21128	21128	19 provided in a language in which the customer subject to
21129	21129	20 the marketing or solicitation is able to understand and
21130	21130	21 communicate, and the alternative retail electric supplier
21131	21131	22 shall not switch a customer who is unable to understand
21132	21132	23 and communicate in a language in which the marketing or
21133	21133	24 solicitation was conducted. The alternative retail
21134	21134	25 electric supplier shall comply with Section 2N of the
21135	21135	26 Consumer Fraud and Deceptive Business Practices Act.
21136	21136
21137	21137
21138	21138
21139	21139
21140	21140
21141	21141	HB3779 - 588 - LRB104 11172 AAS 21254 b
21142	21142
21143	21143
21144	21144	HB3779- 589 -LRB104 11172 AAS 21254 b HB3779 - 589 - LRB104 11172 AAS 21254 b
21145	21145	HB3779 - 589 - LRB104 11172 AAS 21254 b
21146	21146	1 (iii) An alternative retail electric supplier shall
21147	21147	2 provide documentation to the Commission and to customers
21148	21148	3 that substantiates any claims made by the alternative
21149	21149	4 retail electric supplier regarding the technologies and
21150	21150	5 fuel types used to generate the electricity offered or
21151	21151	6 sold to customers.
21152	21152	7 (iv) The alternative retail electric supplier shall
21153	21153	8 provide to the customer (1) itemized billing statements
21154	21154	9 that describe the products and services provided to the
21155	21155	10 customer and their prices, and (2) an additional
21156	21156	11 statement, at least annually, that adequately discloses
21157	21157	12 the average monthly prices, and the terms and conditions,
21158	21158	13 of the products and services sold to the customer.
21159	21159	14 (v) All in-person and telephone solicitations shall be
21160	21160	15 conducted in, translated into, and provided in a language
21161	21161	16 in which the consumer subject to the marketing or
21162	21162	17 solicitation is able to understand and communicate. An
21163	21163	18 alternative retail electric supplier shall terminate a
21164	21164	19 solicitation if the consumer subject to the marketing or
21165	21165	20 communication is unable to understand and communicate in
21166	21166	21 the language in which the marketing or solicitation is
21167	21167	22 being conducted. An alternative retail electric supplier
21168	21168	23 shall comply with Section 2N of the Consumer Fraud and
21169	21169	24 Deceptive Business Practices Act.
21170	21170	25 (vi) Each alternative retail electric supplier shall
21171	21171	26 conduct training for individual representatives engaged in
21172	21172
21173	21173
21174	21174
21175	21175
21176	21176
21177	21177	HB3779 - 589 - LRB104 11172 AAS 21254 b
21178	21178
21179	21179
21180	21180	HB3779- 590 -LRB104 11172 AAS 21254 b HB3779 - 590 - LRB104 11172 AAS 21254 b
21181	21181	HB3779 - 590 - LRB104 11172 AAS 21254 b
21182	21182	1 in-person solicitation and telemarketing to residential
21183	21183	2 customers on behalf of that alternative retail electric
21184	21184	3 supplier prior to conducting any such solicitations on the
21185	21185	4 alternative retail electric supplier's behalf. Each
21186	21186	5 alternative retail electric supplier shall submit a copy
21187	21187	6 of its training material to the Commission on an annual
21188	21188	7 basis and the Commission shall have the right to review
21189	21189	8 and require updates to the material. After initial
21190	21190	9 training, each alternative retail electric supplier shall
21191	21191	10 be required to conduct refresher training for its
21192	21192	11 individual representatives every 6 months.
21193	21193	12 (f) An alternative retail electric supplier may limit the
21194	21194	13 overall size or availability of a service offering by
21195	21195	14 specifying one or more of the following: a maximum number of
21196	21196	15 customers, maximum amount of electric load to be served, time
21197	21197	16 period during which the offering will be available, or other
21198	21198	17 comparable limitation, but not including the geographic
21199	21199	18 locations of customers within the area which the alternative
21200	21200	19 retail electric supplier is certificated to serve. The
21201	21201	20 alternative retail electric supplier shall file the terms and
21202	21202	21 conditions of such service offering including the applicable
21203	21203	22 limitations with the Commission prior to making the service
21204	21204	23 offering available to customers.
21205	21205	24 (g) Nothing in this Section shall be construed as
21206	21206	25 preventing an alternative retail electric supplier, which is
21207	21207	26 an affiliate of, or which contracts with, (i) an industry or
21208	21208
21209	21209
21210	21210
21211	21211
21212	21212
21213	21213	HB3779 - 590 - LRB104 11172 AAS 21254 b
21214	21214
21215	21215
21216	21216	HB3779- 591 -LRB104 11172 AAS 21254 b HB3779 - 591 - LRB104 11172 AAS 21254 b
21217	21217	HB3779 - 591 - LRB104 11172 AAS 21254 b
21218	21218	1 trade organization or association, (ii) a membership
21219	21219	2 organization or association that exists for a purpose other
21220	21220	3 than the purchase of electricity, or (iii) another
21221	21221	4 organization that meets criteria established in a rule adopted
21222	21222	5 by the Commission, from offering through the organization or
21223	21223	6 association services at prices, terms and conditions that are
21224	21224	7 available solely to the members of the organization or
21225	21225	8 association.
21226	21226	9 (h) For all potentially eligible retail customers, as
21227	21227	10 defined in Section 16-111.5, served by an alternative retail
21228	21228	11 electric supplier, or electric utility other than the electric
21229	21229	12 utility in whose service area a customer is located, such
21230	21230	13 supplier or utility shall purchase products that include the
21231	21231	14 same percentage of renewable energy resources, as defined in
21232	21232	15 Section 1-10 of the Illinois Power Agency Act, as was procured
21233	21233	16 for the utility in whose service area such customers are
21234	21234	17 located for the immediately prior delivery year. Such clean
21235	21235	18 energy shall include all environmental attributes as described
21236	21236	19 in Section 16-111.5 and match the eligibility criteria of
21237	21237	20 resources eligible for the renewable portfolio standard
21238	21238	21 described in subsections (c)(I) and (c)(J) of Section 1-75 of
21239	21239	22 the Illinois Power Agency Act.
21240	21240	23 (Source: P.A. 102-459, eff. 8-20-21; 103-237, eff. 6-30-23.)
21241	21241	24 (220 ILCS 5/16-115D)
21242	21242	25 Sec. 16-115D. Renewable portfolio standard for alternative
21243	21243
21244	21244
21245	21245
21246	21246
21247	21247
21248	21248	HB3779 - 591 - LRB104 11172 AAS 21254 b
21249	21249
21250	21250
21251	21251	HB3779- 592 -LRB104 11172 AAS 21254 b HB3779 - 592 - LRB104 11172 AAS 21254 b
21252	21252	HB3779 - 592 - LRB104 11172 AAS 21254 b
21253	21253	1 retail electric suppliers and electric utilities operating
21254	21254	2 outside their service territories.
21255	21255	3 (a) An alternative retail electric supplier shall be
21256	21256	4 responsible for procuring cost-effective renewable energy
21257	21257	5 resources as required under item (5) of subsection (d) of
21258	21258	6 Section 16-115 of this Act as outlined herein:
21259	21259	7 (1) The definition of renewable energy resources
21260	21260	8 contained in Section 1-10 of the Illinois Power Agency Act
21261	21261	9 applies to all renewable energy resources required to be
21262	21262	10 procured by alternative retail electric suppliers.
21263	21263	11 (2) Through May 31, 2017, the quantity of renewable
21264	21264	12 energy resources shall be measured as a percentage of the
21265	21265	13 actual amount of metered electricity (megawatt-hours)
21266	21266	14 delivered by the alternative retail electric supplier to
21267	21267	15 Illinois retail customers during the 12-month period June
21268	21268	16 1 through May 31, commencing June 1, 2009, and the
21269	21269	17 comparable 12-month period in each year thereafter except
21270	21270	18 as provided in item (6) of this subsection (a).
21271	21271	19 (3) Through May 31, 2017, the quantity of renewable
21272	21272	20 energy resources shall be in amounts at least equal to the
21273	21273	21 annual percentages set forth in item (1) of subsection (c)
21274	21274	22 of Section 1-75 of the Illinois Power Agency Act. At least
21275	21275	23 60% of the renewable energy resources procured pursuant to
21276	21276	24 items (1) and (3) of subsection (b) of this Section shall
21277	21277	25 come from wind generation and, starting June 1, 2015, at
21278	21278	26 least 6% of the renewable energy resources procured
21279	21279
21280	21280
21281	21281
21282	21282
21283	21283
21284	21284	HB3779 - 592 - LRB104 11172 AAS 21254 b
21285	21285
21286	21286
21287	21287	HB3779- 593 -LRB104 11172 AAS 21254 b HB3779 - 593 - LRB104 11172 AAS 21254 b
21288	21288	HB3779 - 593 - LRB104 11172 AAS 21254 b
21289	21289	1 pursuant to items (1) and (3) of subsection (b) of this
21290	21290	2 Section shall come from solar photovoltaics. If, in any
21291	21291	3 given year, an alternative retail electric supplier does
21292	21292	4 not purchase at least these levels of renewable energy
21293	21293	5 resources, then the alternative retail electric supplier
21294	21294	6 shall make alternative compliance payments, as described
21295	21295	7 in subsection (d) of this Section.
21296	21296	8 (3.5) For the delivery year commencing June 1, 2017,
21297	21297	9 the quantity of renewable energy resources shall be at
21298	21298	10 least 13.0% of the uncovered amount of metered electricity
21299	21299	11 (megawatt-hours) delivered by the alternative retail
21300	21300	12 electric supplier to Illinois retail customers during the
21301	21301	13 delivery year, which uncovered amount shall equal 50% of
21302	21302	14 such metered electricity delivered by the alternative
21303	21303	15 retail electric supplier. For the delivery year commencing
21304	21304	16 June 1, 2018, the quantity of renewable energy resources
21305	21305	17 shall be at least 14.5% of the uncovered amount of metered
21306	21306	18 electricity (megawatt-hours) delivered by the alternative
21307	21307	19 retail electric supplier to Illinois retail customers
21308	21308	20 during the delivery year, which uncovered amount shall
21309	21309	21 equal 25% of such metered electricity delivered by the
21310	21310	22 alternative retail electric supplier. At least 32% of the
21311	21311	23 renewable energy resources procured by the alternative
21312	21312	24 retail electric supplier for its uncovered portion under
21313	21313	25 this paragraph (3.5) shall come from wind or photovoltaic
21314	21314	26 generation. The renewable energy resources procured under
21315	21315
21316	21316
21317	21317
21318	21318
21319	21319
21320	21320	HB3779 - 593 - LRB104 11172 AAS 21254 b
21321	21321
21322	21322
21323	21323	HB3779- 594 -LRB104 11172 AAS 21254 b HB3779 - 594 - LRB104 11172 AAS 21254 b
21324	21324	HB3779 - 594 - LRB104 11172 AAS 21254 b
21325	21325	1 this paragraph (3.5) shall not include any resources from
21326	21326	2 a facility whose costs were being recovered through rates
21327	21327	3 regulated by any state or states on or after January 1,
21328	21328	4 2017.
21329	21329	5 (4) The quantity and source of renewable energy
21330	21330	6 resources shall be independently verified through the PJM
21331	21331	7 Environmental Information System Generation Attribute
21332	21332	8 Tracking System (PJM-GATS) or the Midwest Renewable Energy
21333	21333	9 Tracking System (M-RETS), which shall document the
21334	21334	10 location of generation, resource type, month, and year of
21335	21335	11 generation for all qualifying renewable energy resources
21336	21336	12 that an alternative retail electric supplier uses to
21337	21337	13 comply with this Section. No later than June 1, 2009, the
21338	21338	14 Illinois Power Agency shall provide PJM-GATS, M-RETS, and
21339	21339	15 alternative retail electric suppliers with all information
21340	21340	16 necessary to identify resources located in Illinois,
21341	21341	17 within states that adjoin Illinois or within portions of
21342	21342	18 the PJM and MISO footprint in the United States that
21343	21343	19 qualify under the definition of renewable energy resources
21344	21344	20 in Section 1-10 of the Illinois Power Agency Act for
21345	21345	21 compliance with this Section 16-115D. Alternative retail
21346	21346	22 electric suppliers shall not be subject to the
21347	21347	23 requirements in item (3) of subsection (c) of Section 1-75
21348	21348	24 of the Illinois Power Agency Act.
21349	21349	25 (5) All renewable energy credits used to comply with
21350	21350	26 this Section shall be permanently retired.
21351	21351
21352	21352
21353	21353
21354	21354
21355	21355
21356	21356	HB3779 - 594 - LRB104 11172 AAS 21254 b
21357	21357
21358	21358
21359	21359	HB3779- 595 -LRB104 11172 AAS 21254 b HB3779 - 595 - LRB104 11172 AAS 21254 b
21360	21360	HB3779 - 595 - LRB104 11172 AAS 21254 b
21361	21361	1 (6) The required procurement of renewable energy
21362	21362	2 resources by an alternative retail electric supplier shall
21363	21363	3 apply to all metered electricity delivered to Illinois
21364	21364	4 retail customers by the alternative retail electric
21365	21365	5 supplier pursuant to contracts executed or extended after
21366	21366	6 March 15, 2009.
21367	21367	7 (b) Compliance obligations.
21368	21368	8 (1) Through May 31, 2017, an alternative retail
21369	21369	9 electric supplier shall comply with the renewable energy
21370	21370	10 portfolio standards by making an alternative compliance
21371	21371	11 payment, as described in subsection (d) of this Section,
21372	21372	12 to cover at least one-half of the alternative retail
21373	21373	13 electric supplier's compliance obligation for the period
21374	21374	14 prior to June 1, 2017.
21375	21375	15 (2) For the delivery years beginning June 1, 2017 and
21376	21376	16 June 1, 2018, an alternative retail electric supplier need
21377	21377	17 not make any alternative compliance payment to meet any
21378	21378	18 portion of its compliance obligation, as set forth in
21379	21379	19 paragraph (3.5) of subsection (a) of this Section.
21380	21380	20 (3) An alternative retail electric supplier shall use
21381	21381	21 any one or combination of the following means to cover the
21382	21382	22 remainder of the alternative retail electric supplier's
21383	21383	23 compliance obligation, as set forth in paragraphs (3) and
21384	21384	24 (3.5) of subsection (a) of this Section, not covered by an
21385	21385	25 alternative compliance payment made under paragraphs (1)
21386	21386	26 and (2) of this subsection (b) of this Section:
21387	21387
21388	21388
21389	21389
21390	21390
21391	21391
21392	21392	HB3779 - 595 - LRB104 11172 AAS 21254 b
21393	21393
21394	21394
21395	21395	HB3779- 596 -LRB104 11172 AAS 21254 b HB3779 - 596 - LRB104 11172 AAS 21254 b
21396	21396	HB3779 - 596 - LRB104 11172 AAS 21254 b
21397	21397	1 (A) Generating electricity using renewable energy
21398	21398	2 resources identified pursuant to item (4) of
21399	21399	3 subsection (a) of this Section.
21400	21400	4 (B) Purchasing electricity generated using
21401	21401	5 renewable energy resources identified pursuant to item
21402	21402	6 (4) of subsection (a) of this Section through an
21403	21403	7 energy contract.
21404	21404	8 (C) Purchasing renewable energy credits from
21405	21405	9 renewable energy resources identified pursuant to item
21406	21406	10 (4) of subsection (a) of this Section.
21407	21407	11 (D) Making an alternative compliance payment as
21408	21408	12 described in subsection (d) of this Section.
21409	21409	13 (c) Use of renewable energy credits.
21410	21410	14 (1) Renewable energy credits that are not used by an
21411	21411	15 alternative retail electric supplier to comply with a
21412	21412	16 renewable portfolio standard in a compliance year may be
21413	21413	17 banked and carried forward up to 2 12-month compliance
21414	21414	18 periods after the compliance period in which the credit
21415	21415	19 was generated for the purpose of complying with a
21416	21416	20 renewable portfolio standard in those 2 subsequent
21417	21417	21 compliance periods. For the 2009-2010 and 2010-2011
21418	21418	22 compliance periods, an alternative retail electric
21419	21419	23 supplier may use renewable credits generated after
21420	21420	24 December 31, 2008 and before June 1, 2009 to comply with
21421	21421	25 this Section.
21422	21422	26 (2) An alternative retail electric supplier is
21423	21423
21424	21424
21425	21425
21426	21426
21427	21427
21428	21428	HB3779 - 596 - LRB104 11172 AAS 21254 b
21429	21429
21430	21430
21431	21431	HB3779- 597 -LRB104 11172 AAS 21254 b HB3779 - 597 - LRB104 11172 AAS 21254 b
21432	21432	HB3779 - 597 - LRB104 11172 AAS 21254 b
21433	21433	1 responsible for demonstrating that a renewable energy
21434	21434	2 credit used to comply with a renewable portfolio standard
21435	21435	3 is derived from a renewable energy resource and that the
21436	21436	4 alternative retail electric supplier has not used, traded,
21437	21437	5 sold, or otherwise transferred the credit.
21438	21438	6 (3) The same renewable energy credit may be used by an
21439	21439	7 alternative retail electric supplier to comply with a
21440	21440	8 federal renewable portfolio standard and a renewable
21441	21441	9 portfolio standard established under this Act. An
21442	21442	10 alternative retail electric supplier that uses a renewable
21443	21443	11 energy credit to comply with a renewable portfolio
21444	21444	12 standard imposed by any other state may not use the same
21445	21445	13 credit to comply with a renewable portfolio standard
21446	21446	14 established under this Act.
21447	21447	15 (d) Alternative compliance payments.
21448	21448	16 (1) The Commission shall establish and post on its
21449	21449	17 website, within 5 business days after entering an order
21450	21450	18 approving a procurement plan pursuant to Section 1-75 of
21451	21451	19 the Illinois Power Agency Act, maximum alternative
21452	21452	20 compliance payment rates, expressed on a per kilowatt-hour
21453	21453	21 basis, that will be applicable in the first compliance
21454	21454	22 period following the plan approval. A separate maximum
21455	21455	23 alternative compliance payment rate shall be established
21456	21456	24 for the service territory of each electric utility that is
21457	21457	25 subject to subsection (c) of Section 1-75 of the Illinois
21458	21458	26 Power Agency Act. Each maximum alternative compliance
21459	21459
21460	21460
21461	21461
21462	21462
21463	21463
21464	21464	HB3779 - 597 - LRB104 11172 AAS 21254 b
21465	21465
21466	21466
21467	21467	HB3779- 598 -LRB104 11172 AAS 21254 b HB3779 - 598 - LRB104 11172 AAS 21254 b
21468	21468	HB3779 - 598 - LRB104 11172 AAS 21254 b
21469	21469	1 payment rate shall be equal to the maximum allowable
21470	21470	2 annual estimated average net increase due to the costs of
21471	21471	3 the utility's purchase of renewable energy resources
21472	21472	4 included in the amounts paid by eligible retail customers
21473	21473	5 in connection with electric service, as described in item
21474	21474	6 (2) of subsection (c) of Section 1-75 of the Illinois
21475	21475	7 Power Agency Act for the compliance period, and as
21476	21476	8 established in the approved procurement plan. Following
21477	21477	9 each procurement event through which renewable energy
21478	21478	10 resources are purchased for one or more of these utilities
21479	21479	11 for the compliance period, the Commission shall establish
21480	21480	12 and post on its website estimates of the alternative
21481	21481	13 compliance payment rates, expressed on a per kilowatt-hour
21482	21482	14 basis, that shall apply for that compliance period.
21483	21483	15 Posting of the estimates shall occur no later than 10
21484	21484	16 business days following the procurement event, however,
21485	21485	17 the Commission shall not be required to establish and post
21486	21486	18 such estimates more often than once per calendar month. By
21487	21487	19 July 1 of each year, the Commission shall establish and
21488	21488	20 post on its website the actual alternative compliance
21489	21489	21 payment rates for the preceding compliance year. For
21490	21490	22 compliance years beginning prior to June 1, 2014, each
21491	21491	23 alternative compliance payment rate shall be equal to the
21492	21492	24 total amount of dollars that the utility contracted to
21493	21493	25 spend on renewable resources, excepting the additional
21494	21494	26 incremental cost attributable to solar resources, for the
21495	21495
21496	21496
21497	21497
21498	21498
21499	21499
21500	21500	HB3779 - 598 - LRB104 11172 AAS 21254 b
21501	21501
21502	21502
21503	21503	HB3779- 599 -LRB104 11172 AAS 21254 b HB3779 - 599 - LRB104 11172 AAS 21254 b
21504	21504	HB3779 - 599 - LRB104 11172 AAS 21254 b
21505	21505	1 compliance period divided by the forecasted load of
21506	21506	2 eligible retail customers, at the customers' meters, as
21507	21507	3 previously established in the Commission-approved
21508	21508	4 procurement plan for that compliance year. For compliance
21509	21509	5 years commencing on or after June 1, 2014, each
21510	21510	6 alternative compliance payment rate shall be equal to the
21511	21511	7 total amount of dollars that the utility contracted to
21512	21512	8 spend on all renewable resources for the compliance period
21513	21513	9 divided by the forecasted load of retail customers for
21514	21514	10 which the utility is procuring renewable energy resources
21515	21515	11 in a given delivery year, at the customers' meters, as
21516	21516	12 previously established in the Commission-approved
21517	21517	13 procurement plan for that compliance year. The actual
21518	21518	14 alternative compliance payment rates may not exceed the
21519	21519	15 maximum alternative compliance payment rates established
21520	21520	16 for the compliance period. For purposes of this subsection
21521	21521	17 (d), the term "eligible retail customers" has the same
21522	21522	18 meaning as found in Section 16-111.5 of this Act.
21523	21523	19 (2) In any given compliance year, an alternative
21524	21524	20 retail electric supplier may elect to use alternative
21525	21525	21 compliance payments to comply with all or a part of the
21526	21526	22 applicable renewable portfolio standard. In the event that
21527	21527	23 an alternative retail electric supplier elects to make
21528	21528	24 alternative compliance payments to comply with all or a
21529	21529	25 part of the applicable renewable portfolio standard, such
21530	21530	26 payments shall be made by September 1, 2010 for the period
21531	21531
21532	21532
21533	21533
21534	21534
21535	21535
21536	21536	HB3779 - 599 - LRB104 11172 AAS 21254 b
21537	21537
21538	21538
21539	21539	HB3779- 600 -LRB104 11172 AAS 21254 b HB3779 - 600 - LRB104 11172 AAS 21254 b
21540	21540	HB3779 - 600 - LRB104 11172 AAS 21254 b
21541	21541	1 of June 1, 2009 to May 1, 2010 and by September 1 of each
21542	21542	2 year thereafter for the subsequent compliance period, in
21543	21543	3 the manner and form as determined by the Commission. Any
21544	21544	4 election by an alternative retail electric supplier to use
21545	21545	5 alternative compliance payments is subject to review by
21546	21546	6 the Commission under subsection (e) of this Section.
21547	21547	7 (3) An alternative retail electric supplier's
21548	21548	8 alternative compliance payments shall be computed
21549	21549	9 separately for each electric utility's service territory
21550	21550	10 within which the alternative retail electric supplier
21551	21551	11 provided retail service during the compliance period,
21552	21552	12 provided that the electric utility was subject to
21553	21553	13 subsection (c) of Section 1-75 of the Illinois Power
21554	21554	14 Agency Act. For each service territory, the alternative
21555	21555	15 retail electric supplier's alternative compliance payment
21556	21556	16 shall be equal to (i) the actual alternative compliance
21557	21557	17 payment rate established in item (1) of this subsection
21558	21558	18 (d), multiplied by (ii) the actual amount of metered
21559	21559	19 electricity delivered by the alternative retail electric
21560	21560	20 supplier to retail customers for which the supplier has a
21561	21561	21 compliance obligation within the service territory during
21562	21562	22 the compliance period, multiplied by (iii) the result of
21563	21563	23 one minus the ratios of the quantity of renewable energy
21564	21564	24 resources used by the alternative retail electric supplier
21565	21565	25 to comply with the requirements of this Section within the
21566	21566	26 service territory to the product of the percentage of
21567	21567
21568	21568
21569	21569
21570	21570
21571	21571
21572	21572	HB3779 - 600 - LRB104 11172 AAS 21254 b
21573	21573
21574	21574
21575	21575	HB3779- 601 -LRB104 11172 AAS 21254 b HB3779 - 601 - LRB104 11172 AAS 21254 b
21576	21576	HB3779 - 601 - LRB104 11172 AAS 21254 b
21577	21577	1 renewable energy resources required under item (3) or
21578	21578	2 (3.5) of subsection (a) of this Section and the actual
21579	21579	3 amount of metered electricity delivered by the alternative
21580	21580	4 retail electrical supplier to retail customers for which
21581	21581	5 the supplier has a compliance obligation within the
21582	21582	6 service territory during the compliance period.
21583	21583	7 (4) Through May 31, 2017, all alternative compliance
21584	21584	8 payments by alternative retail electric suppliers shall be
21585	21585	9 deposited in the Illinois Power Agency Renewable Energy
21586	21586	10 Resources Fund and used to purchase renewable energy
21587	21587	11 credits, in accordance with Section 1-56 of the Illinois
21588	21588	12 Power Agency Act. Beginning April 1, 2012 and by April 1 of
21589	21589	13 each year thereafter, the Illinois Power Agency shall
21590	21590	14 submit an annual report to the General Assembly, the
21591	21591	15 Commission, and alternative retail electric suppliers that
21592	21592	16 shall include, but not be limited to:
21593	21593	17 (A) the total amount of alternative compliance
21594	21594	18 payments received in aggregate from alternative retail
21595	21595	19 electric suppliers by planning year for all previous
21596	21596	20 planning years in which the alternative compliance
21597	21597	21 payment was in effect;
21598	21598	22 (B) the amount of those payments utilized to
21599	21599	23 purchased renewable energy credits itemized by the
21600	21600	24 date of each procurement in which the payments were
21601	21601	25 utilized; and
21602	21602	26 (C) the unused and remaining balance in the Agency
21603	21603
21604	21604
21605	21605
21606	21606
21607	21607
21608	21608	HB3779 - 601 - LRB104 11172 AAS 21254 b
21609	21609
21610	21610
21611	21611	HB3779- 602 -LRB104 11172 AAS 21254 b HB3779 - 602 - LRB104 11172 AAS 21254 b
21612	21612	HB3779 - 602 - LRB104 11172 AAS 21254 b
21613	21613	1 Renewable Energy Resources Fund attributable to those
21614	21614	2 payments.
21615	21615	3 (4.5) Beginning with the delivery year commencing June
21616	21616	4 1, 2017, all alternative compliance payments by
21617	21617	5 alternative retail electric suppliers shall be remitted to
21618	21618	6 the applicable electric utility. To facilitate this
21619	21619	7 remittance, each electric utility shall file a tariff with
21620	21620	8 the Commission no later than 30 days following the
21621	21621	9 effective date of this amendatory Act of the 99th General
21622	21622	10 Assembly, which the Commission shall approve, after notice
21623	21623	11 and hearing, no later than 45 days after its filing. The
21624	21624	12 Illinois Power Agency shall use such payments to increase
21625	21625	13 the amount of renewable energy resources otherwise to be
21626	21626	14 procured under subsection (c) of Section 1-75 of the
21627	21627	15 Illinois Power Agency Act.
21628	21628	16 (5) The Commission, in consultation with the Illinois
21629	21629	17 Power Agency, shall establish a process or proceeding to
21630	21630	18 consider the impact of a federal renewable portfolio
21631	21631	19 standard, if enacted, on the operation of the alternative
21632	21632	20 compliance mechanism, which shall include, but not be
21633	21633	21 limited to, developing, to the extent permitted by the
21634	21634	22 applicable federal statute, an appropriate methodology to
21635	21635	23 apportion renewable energy credits retired as a result of
21636	21636	24 alternative compliance payments made in accordance with
21637	21637	25 this Section. The Commission shall commence any such
21638	21638	26 process or proceeding within 35 days after enactment of a
21639	21639
21640	21640
21641	21641
21642	21642
21643	21643
21644	21644	HB3779 - 602 - LRB104 11172 AAS 21254 b
21645	21645
21646	21646
21647	21647	HB3779- 603 -LRB104 11172 AAS 21254 b HB3779 - 603 - LRB104 11172 AAS 21254 b
21648	21648	HB3779 - 603 - LRB104 11172 AAS 21254 b
21649	21649	1 federal renewable portfolio standard.
21650	21650	2 (e) Each alternative retail electric supplier shall, by
21651	21651	3 September 1, 2010 and by September 1 of each year thereafter,
21652	21652	4 prepare and submit to the Commission a report, in a format to
21653	21653	5 be specified by the Commission, that provides information
21654	21654	6 certifying compliance by the alternative retail electric
21655	21655	7 supplier with this Section, including copies of all PJM-GATS
21656	21656	8 and M-RETS reports, and documentation relating to banking,
21657	21657	9 retiring renewable energy credits, and any other information
21658	21658	10 that the Commission determines necessary to ensure compliance
21659	21659	11 with this Section.
21660	21660	12 An alternative retail electric supplier may file
21661	21661	13 commercially or financially sensitive information or trade
21662	21662	14 secrets with the Commission as provided under the rules of the
21663	21663	15 Commission. To be filed confidentially, the information shall
21664	21664	16 be accompanied by an affidavit that sets forth both the
21665	21665	17 reasons for the confidentiality and a public synopsis of the
21666	21666	18 information.
21667	21667	19 (f) The Commission may initiate a contested case to review
21668	21668	20 allegations that the alternative retail electric supplier has
21669	21669	21 violated this Section, including an order issued or rule
21670	21670	22 promulgated under this Section. In any such proceeding, the
21671	21671	23 alternative retail electric supplier shall have the burden of
21672	21672	24 proof. If the Commission finds, after notice and hearing, that
21673	21673	25 an alternative retail electric supplier has violated this
21674	21674	26 Section, then the Commission shall issue an order requiring
21675	21675
21676	21676
21677	21677
21678	21678
21679	21679
21680	21680	HB3779 - 603 - LRB104 11172 AAS 21254 b
21681	21681
21682	21682
21683	21683	HB3779- 604 -LRB104 11172 AAS 21254 b HB3779 - 604 - LRB104 11172 AAS 21254 b
21684	21684	HB3779 - 604 - LRB104 11172 AAS 21254 b
21685	21685	1 the alternative retail electric supplier to:
21686	21686	2 (1) immediately comply with this Section; and
21687	21687	3 (2) if the violation involves a failure to procure the
21688	21688	4 requisite quantity of renewable energy resources or pay
21689	21689	5 the applicable alternative compliance payment by the
21690	21690	6 annual deadline, the Commission shall require the
21691	21691	7 alternative retail electric supplier to double the
21692	21692	8 applicable alternative compliance payment that would
21693	21693	9 otherwise be required to bring the alternative retail
21694	21694	10 electric supplier into compliance with this Section.
21695	21695	11 If an alternative retail electric supplier fails to comply
21696	21696	12 with the renewable energy resource portfolio requirement or
21697	21697	13 capacity portfolio requirement in this Section more than once
21698	21698	14 in a 5-year period, then the Commission shall revoke the
21699	21699	15 alternative electric supplier's certificate of service
21700	21700	16 authority. The Commission shall not accept an application for
21701	21701	17 a certificate of service authority from an alternative retail
21702	21702	18 electric supplier that has lost certification under this
21703	21703	19 subsection (f), or any corporate affiliate thereof, for at
21704	21704	20 least one year after the date of revocation.
21705	21705	21 (g) All of the provisions of this Section apply to
21706	21706	22 electric utilities operating outside their service area except
21707	21707	23 under item (2) of subsection (a) of this Section the quantity
21708	21708	24 of renewable energy resources shall be measured as a
21709	21709	25 percentage of the actual amount of electricity
21710	21710	26 (megawatt-hours) supplied in the State outside of the
21711	21711
21712	21712
21713	21713
21714	21714
21715	21715
21716	21716	HB3779 - 604 - LRB104 11172 AAS 21254 b
21717	21717
21718	21718
21719	21719	HB3779- 605 -LRB104 11172 AAS 21254 b HB3779 - 605 - LRB104 11172 AAS 21254 b
21720	21720	HB3779 - 605 - LRB104 11172 AAS 21254 b
21721	21721	1 utility's service territory during the 12-month period June 1
21722	21722	2 through May 31, commencing June 1, 2009, and the comparable
21723	21723	3 12-month period in each year thereafter except as provided in
21724	21724	4 item (6) of subsection (a) of this Section.
21725	21725	5 If any such utility fails to procure the requisite
21726	21726	6 quantity of renewable energy resources by the annual deadline,
21727	21727	7 then the Commission shall require the utility to double the
21728	21728	8 alternative compliance payment that would otherwise be
21729	21729	9 required to bring the utility into compliance with this
21730	21730	10 Section.
21731	21731	11 If any such utility fails to comply with the renewable
21732	21732	12 energy resource portfolio requirement in this Section more
21733	21733	13 than once in a 5-year period, then the Commission shall order
21734	21734	14 the utility to cease all sales outside of the utility's
21735	21735	15 service territory for a period of at least one year.
21736	21736	16 (h) The provisions of this Section and the provisions of
21737	21737	17 subsection (d) of Section 16-115 of this Act relating to
21738	21738	18 procurement of renewable energy resources shall not apply to
21739	21739	19 an alternative retail electric supplier that operates a
21740	21740	20 combined heat and power system in this State or that has a
21741	21741	21 corporate affiliate that operates such a combined heat and
21742	21742	22 power system in this State that supplies electricity primarily
21743	21743	23 to or for the benefit of: (i) facilities owned by the supplier,
21744	21744	24 its subsidiary, or other corporate affiliate; (ii) facilities
21745	21745	25 electrically integrated with the electrical system of
21746	21746	26 facilities owned by the supplier, its subsidiary, or other
21747	21747
21748	21748
21749	21749
21750	21750
21751	21751
21752	21752	HB3779 - 605 - LRB104 11172 AAS 21254 b
21753	21753
21754	21754
21755	21755	HB3779- 606 -LRB104 11172 AAS 21254 b HB3779 - 606 - LRB104 11172 AAS 21254 b
21756	21756	HB3779 - 606 - LRB104 11172 AAS 21254 b
21757	21757	1 corporate affiliate; or (iii) facilities that are adjacent to
21758	21758	2 the site on which the combined heat and power system is
21759	21759	3 located.
21760	21760	4 (i) The obligations of alternative retail electric
21761	21761	5 suppliers and electric utilities operating outside their
21762	21762	6 service territories to procure renewable energy resources,
21763	21763	7 make alternative compliance payments, and file annual reports,
21764	21764	8 and the obligations of the Commission to determine and post
21765	21765	9 alternative compliance payment rates, shall terminate after
21766	21766	10 May 31, 2019, provided that alternative retail electric
21767	21767	11 suppliers and electric utilities operating outside their
21768	21768	12 service territories shall be obligated to make all alternative
21769	21769	13 compliance payments that they were obligated to pay for
21770	21770	14 periods through and including May 31, 2019, but were not paid
21771	21771	15 as of that date. The Commission shall continue to enforce the
21772	21772	16 payment of unpaid alternative compliance payments in
21773	21773	17 accordance with subsections (f) and (g) of this Section. All
21774	21774	18 alternative compliance payments made after May 31, 2016 shall
21775	21775	19 be remitted to the applicable electric utility and used to
21776	21776	20 purchase renewable energy credits, in accordance with Section
21777	21777	21 1-75 of the Illinois Power Agency Act.
21778	21778	22 This subsection (i) is intended to accommodate the
21779	21779	23 transition to the procurement of renewable energy resources
21780	21780	24 for all retail customers in the amounts specified under
21781	21781	25 subsection (c) of Section 1-75 of the Illinois Power Agency
21782	21782	26 Act and Section 16-111.5 of this Act, including but not
21783	21783
21784	21784
21785	21785
21786	21786
21787	21787
21788	21788	HB3779 - 606 - LRB104 11172 AAS 21254 b
21789	21789
21790	21790
21791	21791	HB3779- 607 -LRB104 11172 AAS 21254 b HB3779 - 607 - LRB104 11172 AAS 21254 b
21792	21792	HB3779 - 607 - LRB104 11172 AAS 21254 b
21793	21793	1 limited to the transition to a single charge applicable to all
21794	21794	2 retail customers to recover the costs of these resources. Each
21795	21795	3 alternative retail electric supplier shall certify in its
21796	21796	4 annual reports filed pursuant to subsection (e) of this
21797	21797	5 Section after May 31, 2019, that its retail customers are not
21798	21798	6 paying the costs of alternative compliance payments or
21799	21799	7 renewable energy resources that the alternative retail
21800	21800	8 electric supplier is not required to remit or purchase under
21801	21801	9 this Section. The Commission shall have the authority to
21802	21802	10 initiate an emergency rulemaking to adopt rules regarding such
21803	21803	11 certification.
21804	21804	12 (Source: P.A. 99-906, eff. 6-1-17.)
21805	21805	13 (220 ILCS 5/17-500)
21806	21806	14 Sec. 17-500. Jurisdiction. Except as provided in the
21807	21807	15 Electric Supplier Act, the Illinois Municipal Code, the
21808	21808	16 Municipal and Cooperative Electric Utility Planning and
21809	21809	17 Transparency Act, and this Article XVII, the Commission, or
21810	21810	18 any other agency or subdivision thereof of the State of
21811	21811	19 Illinois or any private entity shall have no jurisdiction over
21812	21812	20 any electric cooperative or municipal system regardless of
21813	21813	21 whether any election or elections as provided for herein have
21814	21814	22 been made, and all control regarding an electric cooperative
21815	21815	23 or municipal system shall be vested in the electric
21816	21816	24 cooperative's board of directors or trustees or the applicable
21817	21817	25 governing body of the municipal system.
21818	21818
21819	21819
21820	21820
21821	21821
21822	21822
21823	21823	HB3779 - 607 - LRB104 11172 AAS 21254 b
21824	21824
21825	21825
21826	21826	HB3779- 608 -LRB104 11172 AAS 21254 b HB3779 - 608 - LRB104 11172 AAS 21254 b
21827	21827	HB3779 - 608 - LRB104 11172 AAS 21254 b
21828	21828	1 (Source: P.A. 90-561, eff. 12-16-97.)
21829	21829	2 (220 ILCS 5/17-900)
21830	21830	3 Sec. 17-900. Customer self-generation of electricity.
21831	21831	4 (a) The General Assembly finds and declares that municipal
21832	21832	5 utility systems and electric cooperatives shall continue to be
21833	21833	6 governed by their respective governing bodies, but that such
21834	21834	7 governing bodies should recognize and implement policies to
21835	21835	8 provide the opportunity for their residential and small
21836	21836	9 commercial customers who wish to self-generate electricity and
21837	21837	10 for reasonable credits to customers for excess electricity,
21838	21838	11 balanced against the rights of the other non-self-generating
21839	21839	12 customers. This includes creating consistent, fair policies
21840	21840	13 that are accessible to all customers and transparent, fair
21841	21841	14 processes for raising and addressing any concerns.
21842	21842	15 (b) Customers have the right to install renewable
21843	21843	16 generating facilities to be located on the customer's premises
21844	21844	17 or customer's side of the billing meter and that are intended
21845	21845	18 primarily to offset the customer's own electrical requirements
21846	21846	19 and produce, consume, and store their own renewable energy
21847	21847	20 without discriminatory repercussions from an electric
21848	21848	21 cooperative or municipal utility system. This includes a
21849	21849	22 customer's rights to:
21850	21850	23 (1) generate, consume, and deliver excess renewable
21851	21851	24 energy to the distribution grid and reduce his or her use
21852	21852	25 of electricity obtained from the grid;
21853	21853
21854	21854
21855	21855
21856	21856
21857	21857
21858	21858	HB3779 - 608 - LRB104 11172 AAS 21254 b
21859	21859
21860	21860
21861	21861	HB3779- 609 -LRB104 11172 AAS 21254 b HB3779 - 609 - LRB104 11172 AAS 21254 b
21862	21862	HB3779 - 609 - LRB104 11172 AAS 21254 b
21863	21863	1 (2) use technology to store energy at his or her
21864	21864	2 residence;
21865	21865	3 (3) interconnect his or her electrical system that
21866	21866	4 generates renewable energy, stores energy, or any
21867	21867	5 combination thereof, with the electricity meter on the
21868	21868	6 customer's premises that is provided by an electric
21869	21869	7 cooperative or municipal utility system:
21870	21870	8 (A) in a timely manner;
21871	21871	9 (B) in accordance with requirements established by
21872	21872	10 the electric cooperative or municipal utility to
21873	21873	11 ensure the safety of utility workers; and
21874	21874	12 (C) after providing written notice to the electric
21875	21875	13 cooperative or municipal utility system providing
21876	21876	14 service in the service territory, installing a
21877	21877	15 nomenclature plate on the electrical meter panel and
21878	21878	16 meeting all applicable State and local safety and
21879	21879	17 electrical code requirements associated with
21880	21880	18 installing a parallel distributed generation system;
21881	21881	19 and
21882	21882	20 (4) receive fair credit for excess energy delivered to
21883	21883	21 the distribution grid.
21884	21884	22 (c) The policies of municipal systems and electric
21885	21885	23 cooperatives regarding self-generation and credits for excess
21886	21886	24 electricity may reasonably differ from those required of other
21887	21887	25 entities by Article XVI of the Public Utilities Act or other
21888	21888	26 Acts. The credits must recognize the value of self-generation
21889	21889
21890	21890
21891	21891
21892	21892
21893	21893
21894	21894	HB3779 - 609 - LRB104 11172 AAS 21254 b
21895	21895
21896	21896
21897	21897	HB3779- 610 -LRB104 11172 AAS 21254 b HB3779 - 610 - LRB104 11172 AAS 21254 b
21898	21898	HB3779 - 610 - LRB104 11172 AAS 21254 b
21899	21899	1 to the distribution grid and benefits to other customers.
21900	21900	2 (d) Within 180 days after this amendatory Act of the 102nd
21901	21901	3 General Assembly, each electric cooperative and municipal
21902	21902	4 system shall update its policies for the interconnection and
21903	21903	5 fair crediting of customer self-generation and storage if
21904	21904	6 necessary, to comply with the standards of subsection (b) of
21905	21905	7 this Section. Each electric cooperative and municipal system
21906	21906	8 shall post its updated policies to a public-facing area of its
21907	21907	9 website.
21908	21908	10 (e) An electric cooperative or municipal system customer
21909	21909	11 who produces, consumes, and stores his or her own renewable
21910	21910	12 energy shall not face discriminatory rate design, fees or
21911	21911	13 charges, treatment, or excessive compliance requirements that
21912	21912	14 would unreasonably affect that customer's right to
21913	21913	15 self-generate electricity as provided for in this Section.
21914	21914	16 (f) An electric cooperative or municipal utility system
21915	21915	17 customer shall have a right to appeal any decision related to
21916	21916	18 self-generation and storage that violates these rights to
21917	21917	19 self-generation and non-discrimination pursuant to the
21918	21918	20 provisions of this Section through a complaint under the
21919	21919	21 Administrative Review Law or similar legal process.
21920	21920	22 (Source: P.A. 102-662, eff. 9-15-21.)
21921	21921	23 Section 120. The Environmental Protection Act is amended
21922	21922	24 by changing Section 9.15 as follows:
21923	21923
21924	21924
21925	21925
21926	21926
21927	21927
21928	21928	HB3779 - 610 - LRB104 11172 AAS 21254 b
21929	21929
21930	21930
21931	21931	HB3779- 611 -LRB104 11172 AAS 21254 b HB3779 - 611 - LRB104 11172 AAS 21254 b
21932	21932	HB3779 - 611 - LRB104 11172 AAS 21254 b
21933	21933	1 (415 ILCS 5/9.15)
21934	21934	2 Sec. 9.15. Greenhouse gases.
21935	21935	3 (a) An air pollution construction permit shall not be
21936	21936	4 required due to emissions of greenhouse gases if the
21937	21937	5 equipment, site, or source is not subject to regulation, as
21938	21938	6 defined by 40 CFR 52.21, as now or hereafter amended, for
21939	21939	7 greenhouse gases or is otherwise not addressed in this Section
21940	21940	8 or by the Board in regulations for greenhouse gases. These
21941	21941	9 exemptions do not relieve an owner or operator from the
21942	21942	10 obligation to comply with other applicable rules or
21943	21943	11 regulations.
21944	21944	12 (b) An air pollution operating permit shall not be
21945	21945	13 required due to emissions of greenhouse gases if the
21946	21946	14 equipment, site, or source is not subject to regulation, as
21947	21947	15 defined by Section 39.5 of this Act, for greenhouse gases or is
21948	21948	16 otherwise not addressed in this Section or by the Board in
21949	21949	17 regulations for greenhouse gases. These exemptions do not
21950	21950	18 relieve an owner or operator from the obligation to comply
21951	21951	19 with other applicable rules or regulations.
21952	21952	20 (c) (Blank).
21953	21953	21 (d) (Blank).
21954	21954	22 (e) (Blank).
21955	21955	23 (f) As used in this Section:
21956	21956	24 "Carbon dioxide emission" means the plant annual CO2 total
21957	21957	25 output emission as measured by the United States Environmental
21958	21958	26 Protection Agency in its Emissions & Generation Resource
21959	21959
21960	21960
21961	21961
21962	21962
21963	21963
21964	21964	HB3779 - 611 - LRB104 11172 AAS 21254 b
21965	21965
21966	21966
21967	21967	HB3779- 612 -LRB104 11172 AAS 21254 b HB3779 - 612 - LRB104 11172 AAS 21254 b
21968	21968	HB3779 - 612 - LRB104 11172 AAS 21254 b
21969	21969	1 Integrated Database (eGrid), or its successor.
21970	21970	2 "Carbon dioxide equivalent emissions" or "CO2e" means the
21971	21971	3 sum total of the mass amount of emissions in tons per year,
21972	21972	4 calculated by multiplying the mass amount of each of the 6
21973	21973	5 greenhouse gases specified in Section 3.207, in tons per year,
21974	21974	6 by its associated global warming potential as set forth in 40
21975	21975	7 CFR 98, subpart A, table A-1 or its successor, and then adding
21976	21976	8 them all together.
21977	21977	9 "Cogeneration" or "combined heat and power" refers to any
21978	21978	10 system that, either simultaneously or sequentially, produces
21979	21979	11 electricity and useful thermal energy from a single fuel
21980	21980	12 source.
21981	21981	13 "Copollutants" refers to the 6 criteria pollutants that
21982	21982	14 have been identified by the United States Environmental
21983	21983	15 Protection Agency pursuant to the Clean Air Act.
21984	21984	16 "Electric generating unit" or "EGU" means a fossil
21985	21985	17 fuel-fired stationary boiler, combustion turbine, or combined
21986	21986	18 cycle system that serves a generator that has a nameplate
21987	21987	19 capacity greater than 25 MWe and produces electricity for
21988	21988	20 sale.
21989	21989	21 "Environmental justice community" means the definition of
21990	21990	22 that term based on existing methodologies and findings, used
21991	21991	23 and as may be updated by the Illinois Power Agency and its
21992	21992	24 program administrator in the Illinois Solar for All Program.
21993	21993	25 "Equity investment eligible community" or "eligible
21994	21994	26 community" means the geographic areas throughout Illinois that
21995	21995
21996	21996
21997	21997
21998	21998
21999	21999
22000	22000	HB3779 - 612 - LRB104 11172 AAS 21254 b
22001	22001
22002	22002
22003	22003	HB3779- 613 -LRB104 11172 AAS 21254 b HB3779 - 613 - LRB104 11172 AAS 21254 b
22004	22004	HB3779 - 613 - LRB104 11172 AAS 21254 b
22005	22005	1 would most benefit from equitable investments by the State
22006	22006	2 designed to combat discrimination and foster sustainable
22007	22007	3 economic growth. Specifically, eligible community means the
22008	22008	4 following areas:
22009	22009	5 (1) areas where residents have been historically
22010	22010	6 excluded from economic opportunities, including
22011	22011	7 opportunities in the energy sector, as defined as R3 areas
22012	22012	8 pursuant to Section 10-40 of the Cannabis Regulation and
22013	22013	9 Tax Act; and
22014	22014	10 (2) areas where residents have been historically
22015	22015	11 subject to disproportionate burdens of pollution,
22016	22016	12 including pollution from the energy sector, as established
22017	22017	13 by environmental justice communities as defined by the
22018	22018	14 Illinois Power Agency pursuant to the Illinois Power
22019	22019	15 Agency Act, excluding any racial or ethnic indicators.
22020	22020	16 "Equity investment eligible person" or "eligible person"
22021	22021	17 means the persons who would most benefit from equitable
22022	22022	18 investments by the State designed to combat discrimination and
22023	22023	19 foster sustainable economic growth. Specifically, eligible
22024	22024	20 person means the following people:
22025	22025	21 (1) persons whose primary residence is in an equity
22026	22026	22 investment eligible community;
22027	22027	23 (2) persons whose primary residence is in a
22028	22028	24 municipality, or a county with a population under 100,000,
22029	22029	25 where the closure of an electric generating unit or mine
22030	22030	26 has been publicly announced or the electric generating
22031	22031
22032	22032
22033	22033
22034	22034
22035	22035
22036	22036	HB3779 - 613 - LRB104 11172 AAS 21254 b
22037	22037
22038	22038
22039	22039	HB3779- 614 -LRB104 11172 AAS 21254 b HB3779 - 614 - LRB104 11172 AAS 21254 b
22040	22040	HB3779 - 614 - LRB104 11172 AAS 21254 b
22041	22041	1 unit or mine is in the process of closing or closed within
22042	22042	2 the last 5 years;
22043	22043	3 (3) persons who are graduates of or currently enrolled
22044	22044	4 in the foster care system; or
22045	22045	5 (4) persons who were formerly incarcerated.
22046	22046	6 "Existing emissions" means:
22047	22047	7 (1) for CO2e, the total average tons-per-year of CO2e
22048	22048	8 emitted by the EGU or large GHG-emitting unit either in
22049	22049	9 the years 2018 through 2020 or, if the unit was not yet in
22050	22050	10 operation by January 1, 2018, in the first 3 full years of
22051	22051	11 that unit's operation; and
22052	22052	12 (2) for any copollutant, the total average
22053	22053	13 tons-per-year of that copollutant emitted by the EGU or
22054	22054	14 large GHG-emitting unit either in the years 2018 through
22055	22055	15 2020 or, if the unit was not yet in operation by January 1,
22056	22056	16 2018, in the first 3 full years of that unit's operation.
22057	22057	17 "Green hydrogen" means a power plant technology in which
22058	22058	18 an EGU creates electric power exclusively from electrolytic
22059	22059	19 hydrogen, in a manner that produces zero carbon and
22060	22060	20 copollutant emissions, using hydrogen fuel that is
22061	22061	21 electrolyzed using a 100% renewable zero carbon emission
22062	22062	22 energy source.
22063	22063	23 "Large greenhouse gas-emitting unit" or "large
22064	22064	24 GHG-emitting unit" means a unit that is an electric generating
22065	22065	25 unit or other fossil fuel-fired unit that itself has a
22066	22066	26 nameplate capacity or serves a generator that has a nameplate
22067	22067
22068	22068
22069	22069
22070	22070
22071	22071
22072	22072	HB3779 - 614 - LRB104 11172 AAS 21254 b
22073	22073
22074	22074
22075	22075	HB3779- 615 -LRB104 11172 AAS 21254 b HB3779 - 615 - LRB104 11172 AAS 21254 b
22076	22076	HB3779 - 615 - LRB104 11172 AAS 21254 b
22077	22077	1 capacity greater than 25 MWe and that produces electricity,
22078	22078	2 including, but not limited to, coal-fired, coal-derived,
22079	22079	3 oil-fired, natural gas-fired, and cogeneration units.
22080	22080	4 "NOx emission rate" means the plant annual NOx total output
22081	22081	5 emission rate as measured by the United States Environmental
22082	22082	6 Protection Agency in its Emissions & Generation Resource
22083	22083	7 Integrated Database (eGrid), or its successor, in the most
22084	22084	8 recent year for which data is available.
22085	22085	9 "Public greenhouse gas-emitting units" or "public
22086	22086	10 GHG-emitting unit" means large greenhouse gas-emitting units,
22087	22087	11 including EGUs, that are wholly owned, directly or indirectly,
22088	22088	12 by one or more municipalities, municipal corporations, joint
22089	22089	13 municipal electric power agencies, electric cooperatives, or
22090	22090	14 other governmental or nonprofit entities, whether organized
22091	22091	15 and created under the laws of Illinois or another state.
22092	22092	16 "SO2 emission rate" means the "plant annual SO2 total
22093	22093	17 output emission rate" as measured by the United States
22094	22094	18 Environmental Protection Agency in its Emissions & Generation
22095	22095	19 Resource Integrated Database (eGrid), or its successor, in the
22096	22096	20 most recent year for which data is available.
22097	22097	21 (g) All EGUs and large greenhouse gas-emitting units that
22098	22098	22 use coal or oil as a fuel and are not public GHG-emitting units
22099	22099	23 shall permanently reduce all CO2e and copollutant emissions to
22100	22100	24 zero no later than January 1, 2030.
22101	22101	25 (h) All EGUs and large greenhouse gas-emitting units that
22102	22102	26 use coal as a fuel and are public GHG-emitting units shall
22103	22103
22104	22104
22105	22105
22106	22106
22107	22107
22108	22108	HB3779 - 615 - LRB104 11172 AAS 21254 b
22109	22109
22110	22110
22111	22111	HB3779- 616 -LRB104 11172 AAS 21254 b HB3779 - 616 - LRB104 11172 AAS 21254 b
22112	22112	HB3779 - 616 - LRB104 11172 AAS 21254 b
22113	22113	1 permanently reduce CO2e emissions to zero no later than
22114	22114	2 December 31, 2045. Any source or plant with such units must
22115	22115	3 also reduce their CO2e emissions by 45% from existing
22116	22116	4 emissions by no later than January 1, 2035. If the emissions
22117	22117	5 reduction requirement is not achieved by December 31, 2035,
22118	22118	6 the plant shall retire one or more units or otherwise reduce
22119	22119	7 its CO2e emissions by 45% from existing emissions by June 30,
22120	22120	8 2038.
22121	22121	9 (i) All EGUs and large greenhouse gas-emitting units that
22122	22122	10 use gas as a fuel and are not public GHG-emitting units shall
22123	22123	11 permanently reduce all CO2e and copollutant emissions to zero,
22124	22124	12 including through unit retirement or the use of 100% green
22125	22125	13 hydrogen or other similar technology that is commercially
22126	22126	14 proven to achieve zero carbon emissions, according to the
22127	22127	15 following:
22128	22128	16 (1) No later than January 1, 2030: all EGUs and large
22129	22129	17 greenhouse gas-emitting units that have a NOx emissions
22130	22130	18 rate of greater than 0.12 lbs/MWh or a SO2 emission rate of
22131	22131	19 greater than 0.006 lb/MWh, and are located in or within 3
22132	22132	20 miles of an environmental justice community designated as
22133	22133	21 of January 1, 2021 or an equity investment eligible
22134	22134	22 community.
22135	22135	23 (2) No later than January 1, 2040: all EGUs and large
22136	22136	24 greenhouse gas-emitting units that have a NOx emission
22137	22137	25 rate of greater than 0.12 lbs/MWh or a SO2 emission rate
22138	22138	26 greater than 0.006 lb/MWh, and are not located in or
22139	22139
22140	22140
22141	22141
22142	22142
22143	22143
22144	22144	HB3779 - 616 - LRB104 11172 AAS 21254 b
22145	22145
22146	22146
22147	22147	HB3779- 617 -LRB104 11172 AAS 21254 b HB3779 - 617 - LRB104 11172 AAS 21254 b
22148	22148	HB3779 - 617 - LRB104 11172 AAS 21254 b
22149	22149	1 within 3 miles of an environmental justice community
22150	22150	2 designated as of January 1, 2021 or an equity investment
22151	22151	3 eligible community. After January 1, 2035, each such EGU
22152	22152	4 and large greenhouse gas-emitting unit shall reduce its
22153	22153	5 CO2e emissions by at least 50% from its existing emissions
22154	22154	6 for CO2e, and shall be limited in operation to, on average,
22155	22155	7 6 hours or less per day, measured over a calendar year, and
22156	22156	8 shall not run for more than 24 consecutive hours except in
22157	22157	9 emergency conditions, as designated by a Regional
22158	22158	10 Transmission Organization or Independent System Operator.
22159	22159	11 (3) No later than January 1, 2035: all EGUs and large
22160	22160	12 greenhouse gas-emitting units that began operation prior
22161	22161	13 to the effective date of this amendatory Act of the 102nd
22162	22162	14 General Assembly and have a NOx emission rate of less than
22163	22163	15 or equal to 0.12 lb/MWh and a SO2 emission rate less than
22164	22164	16 or equal to 0.006 lb/MWh, and are located in or within 3
22165	22165	17 miles of an environmental justice community designated as
22166	22166	18 of January 1, 2021 or an equity investment eligible
22167	22167	19 community. Each such EGU and large greenhouse gas-emitting
22168	22168	20 unit shall reduce its CO2e emissions by at least 50% from
22169	22169	21 its existing emissions for CO2e no later than January 1,
22170	22170	22 2030.
22171	22171	23 (4) No later than January 1, 2040: All remaining EGUs
22172	22172	24 and large greenhouse gas-emitting units that have a heat
22173	22173	25 rate greater than or equal to 7000 BTU/kWh. Each such EGU
22174	22174	26 and Large greenhouse gas-emitting unit shall reduce its
22175	22175
22176	22176
22177	22177
22178	22178
22179	22179
22180	22180	HB3779 - 617 - LRB104 11172 AAS 21254 b
22181	22181
22182	22182
22183	22183	HB3779- 618 -LRB104 11172 AAS 21254 b HB3779 - 618 - LRB104 11172 AAS 21254 b
22184	22184	HB3779 - 618 - LRB104 11172 AAS 21254 b
22185	22185	1 CO2e emissions by at least 50% from its existing emissions
22186	22186	2 for CO2e no later than January 1, 2035.
22187	22187	3 (5) No later than January 1, 2045: all remaining EGUs
22188	22188	4 and large greenhouse gas-emitting units.
22189	22189	5 (j) All EGUs and large greenhouse gas-emitting units that
22190	22190	6 use gas as a fuel and are public GHG-emitting units shall
22191	22191	7 permanently reduce all CO2e and copollutant emissions to zero,
22192	22192	8 including through unit retirement or the use of 100% green
22193	22193	9 hydrogen or other similar technology that is commercially
22194	22194	10 proven to achieve zero carbon emissions by January 1, 2045.
22195	22195	11 (k) All EGUs and large greenhouse gas-emitting units that
22196	22196	12 utilize combined heat and power or cogeneration technology
22197	22197	13 shall permanently reduce all CO2e and copollutant emissions to
22198	22198	14 zero, including through unit retirement or the use of 100%
22199	22199	15 green hydrogen or other similar technology that is
22200	22200	16 commercially proven to achieve zero carbon emissions by
22201	22201	17 January 1, 2045.
22202	22202	18 (k-5) No EGU or large greenhouse gas-emitting unit that
22203	22203	19 uses gas as a fuel and is not a public GHG-emitting unit may
22204	22204	20 emit, in any 12-month period, CO2e or copollutants in excess of
22205	22205	21 that unit's existing emissions for those pollutants.
22206	22206	22 (l) Notwithstanding subsections (g) through (k-5), large
22207	22207	23 GHG-emitting units including EGUs may temporarily continue
22208	22208	24 emitting CO2e and copollutants after any applicable deadline
22209	22209	25 specified in any of subsections (g) through (k-5) if it has
22210	22210	26 been determined, as described in paragraphs (1) and (2) of
22211	22211
22212	22212
22213	22213
22214	22214
22215	22215
22216	22216	HB3779 - 618 - LRB104 11172 AAS 21254 b
22217	22217
22218	22218
22219	22219	HB3779- 619 -LRB104 11172 AAS 21254 b HB3779 - 619 - LRB104 11172 AAS 21254 b
22220	22220	HB3779 - 619 - LRB104 11172 AAS 21254 b
22221	22221	1 this subsection, that ongoing operation of the EGU is
22222	22222	2 necessary to maintain power grid supply and reliability or
22223	22223	3 ongoing operation of large GHG-emitting unit that is not an
22224	22224	4 EGU is necessary to serve as an emergency backup to
22225	22225	5 operations. Up to and including the occurrence of an emission
22226	22226	6 reduction deadline under subsection (i), all EGUs and large
22227	22227	7 GHG-emitting units must comply with the following terms:
22228	22228	8 (1) if an EGU or large GHG-emitting unit that is a
22229	22229	9 participant in a regional transmission organization
22230	22230	10 intends to retire, it must submit documentation to the
22231	22231	11 appropriate regional transmission organization by the
22232	22232	12 appropriate deadline that meets all applicable regulatory
22233	22233	13 requirements necessary to obtain approval to permanently
22234	22234	14 cease operating the large GHG-emitting unit;
22235	22235	15 (2) if any EGU or large GHG-emitting unit that is a
22236	22236	16 participant in a regional transmission organization
22237	22237	17 receives notice that the regional transmission
22238	22238	18 organization has determined that continued operation of
22239	22239	19 the unit is required, the unit may continue operating
22240	22240	20 until the issue identified by the regional transmission
22241	22241	21 organization is resolved. The owner or operator of the
22242	22242	22 unit must cooperate with the regional transmission
22243	22243	23 organization in resolving the issue and must reduce its
22244	22244	24 emissions to zero, consistent with the requirements under
22245	22245	25 subsection (g), (h), (i), (j), (k), or (k-5), as
22246	22246	26 applicable, as soon as practicable when the issue
22247	22247
22248	22248
22249	22249
22250	22250
22251	22251
22252	22252	HB3779 - 619 - LRB104 11172 AAS 21254 b
22253	22253
22254	22254
22255	22255	HB3779- 620 -LRB104 11172 AAS 21254 b HB3779 - 620 - LRB104 11172 AAS 21254 b
22256	22256	HB3779 - 620 - LRB104 11172 AAS 21254 b
22257	22257	1 identified by the regional transmission organization is
22258	22258	2 resolved; and
22259	22259	3 (3) any large GHG-emitting unit that is not a
22260	22260	4 participant in a regional transmission organization shall
22261	22261	5 be allowed to continue emitting CO2e and copollutants
22262	22262	6 after the zero-emission date specified in subsection (g),
22263	22263	7 (h), (i), (j), (k), or (k-5), as applicable, in the
22264	22264	8 capacity of an emergency backup unit if approved by the
22265	22265	9 Illinois Commerce Commission.
22266	22266	10 (m) No variance, adjusted standard, or other regulatory
22267	22267	11 relief otherwise available in this Act may be granted to the
22268	22268	12 emissions reduction and elimination obligations in this
22269	22269	13 Section.
22270	22270	14 (n) By June 30 of each year, beginning in 2025, the Agency
22271	22271	15 shall prepare and publish on its website a report setting
22272	22272	16 forth the actual greenhouse gas emissions from individual
22273	22273	17 units and the aggregate statewide emissions from all units for
22274	22274	18 the prior year.
22275	22275	19 (o) Every 5 years beginning in 2025, the Environmental
22276	22276	20 Protection Agency, Illinois Power Agency, in coordination with
22277	22277	21 the and Illinois Commerce Commission and the Environmental
22278	22278	22 Protection Agency, shall jointly prepare, and release
22279	22279	23 publicly, a Clean Resource Plan report to the General Assembly
22280	22280	24 that examines the State's current progress toward its
22281	22281	25 renewable energy resource development goals, the status of
22282	22282	26 CO2e and copollutant emissions reductions, the current status
22283	22283
22284	22284
22285	22285
22286	22286
22287	22287
22288	22288	HB3779 - 620 - LRB104 11172 AAS 21254 b
22289	22289
22290	22290
22291	22291	HB3779- 621 -LRB104 11172 AAS 21254 b HB3779 - 621 - LRB104 11172 AAS 21254 b
22292	22292	HB3779 - 621 - LRB104 11172 AAS 21254 b
22293	22293	1 and progress toward developing and implementing green hydrogen
22294	22294	2 technologies, the current and projected status of electric
22295	22295	3 resource adequacy and reliability throughout the State for the
22296	22296	4 period of ten years after the plan beginning 5 years ahead, and
22297	22297	5 proposed solutions for any findings. The Environmental
22298	22298	6 Protection Agency, Illinois Power Agency, and Illinois
22299	22299	7 Commerce Commission shall consult PJM Interconnection, LLC and
22300	22300	8 Midcontinent Independent System Operator, Inc., or their
22301	22301	9 respective successor organizations regarding forecasted
22302	22302	10 resource adequacy and reliability needs, anticipated new
22303	22303	11 generation interconnection, new transmission development or
22304	22304	12 upgrades, and any announced large GHG-emitting unit closure
22305	22305	13 dates and include this information in the report. The Clean
22306	22306	14 Resource Planreport shall examine multiple scenarios of
22307	22307	15 resource development that would maintain resource adequacy
22308	22308	16 over the ten year planning period and must include scenarios
22309	22309	17 where the requirements for CO2e and copollutant emissions
22310	22310	18 reductions required under subsection (i) and subsection (k-5)
22311	22311	19 of this section, as set out in Public Act 102-0662, are
22312	22312	20 maintained. The multiple scenarios will be used to identify
22313	22313	21 the least-cost energy resource portfolio that maintains
22314	22314	22 resource adequacy and reliability while prioritizing the
22315	22315	23 health and wellbeing of all Illinois residents, particularly
22316	22316	24 those residing in Environmental Justice Communities as defined
22317	22317	25 in IPA Act. The Clean Resource Plan must consider changes to
22318	22318	26 anticipated load growth, including but not limited to, the
22319	22319
22320	22320
22321	22321
22322	22322
22323	22323
22324	22324	HB3779 - 621 - LRB104 11172 AAS 21254 b
22325	22325
22326	22326
22327	22327	HB3779- 622 -LRB104 11172 AAS 21254 b HB3779 - 622 - LRB104 11172 AAS 21254 b
22328	22328	HB3779 - 622 - LRB104 11172 AAS 21254 b
22329	22329	1 electrification of transportation methods and space heating,
22330	22330	2 and the growth of large industrial energy loads, such as data
22331	22331	3 centers. The report shall be structured such that all modeled
22332	22332	4 scenarios avoid resource adequacy shortfalls, including
22333	22333	5 ensuring that there will be sufficient in-state capacity to
22334	22334	6 meet the zonal requirements of MISO Local Resource Zone 4 or
22335	22335	7 the PJM Commonwealth Edison Zone, per the requirements of the
22336	22336	8 respective regional transmission organizations (or any
22337	22337	9 successor construct), and that the modeled portfolios meet
22338	22338	10 reliability standards consistent with best practices in energy
22339	22339	11 resource planning. The Illinois Power Agency, through its
22340	22340	12 Office of Energy Modeling referenced in Section 1-79 of the
22341	22341	13 Illinois Power Agency Act, will take primary responsibility
22342	22342	14 for the Clean Resource Plan described in this subsection. The
22343	22343	15 draft resource plan report shall be released publicly by no
22344	22344	16 later than December 15 of the year it is prepared. The draft
22345	22345	17 Clean Resource Plan will provide an overview of potential
22346	22346	18 resource scenarios and propose a scenario that best serves the
22347	22347	19 people of Illinois by balancing public health and safety,
22348	22348	20 affordability, reliability, resource adequacy, and commitment
22349	22349	21 to reducing CO2e emissions. The draft resource plan will
22350	22350	22 consider and model potential cost savings and reliability
22351	22351	23 benefits of distributed energy resources, as defined in
22352	22352	24 Section 16-107.6 of the Public Utilities Act. If the
22353	22353	25 Environmental Protection Agency, Illinois Power Agency, and
22354	22354	26 Illinois Commerce Commission jointly conclude in the report
22355	22355
22356	22356
22357	22357
22358	22358
22359	22359
22360	22360	HB3779 - 622 - LRB104 11172 AAS 21254 b
22361	22361
22362	22362
22363	22363	HB3779- 623 -LRB104 11172 AAS 21254 b HB3779 - 623 - LRB104 11172 AAS 21254 b
22364	22364	HB3779 - 623 - LRB104 11172 AAS 21254 b
22365	22365	1 that the data from the regional grid operators, the pace of
22366	22366	2 renewable energy development, the pace of development of
22367	22367	3 energy storage and demand response utilization, transmission
22368	22368	4 capacity, and the CO2e and copollutant emissions reductions
22369	22369	5 required by subsection (i) or (k-5) reasonably demonstrate
22370	22370	6 that a resource adequacy shortfall will occur, including
22371	22371	7 whether there will be sufficient in-state capacity to meet the
22372	22372	8 zonal requirements of MISO Zone 4 or the PJM ComEd Zone, per
22373	22373	9 the requirements of the regional transmission organizations,
22374	22374	10 or that the regional transmission operators determine that a
22375	22375	11 reliability violation will occur during the time frame the
22376	22376	12 study is evaluating, then the Illinois Power Agency, in
22377	22377	13 conjunction with the Environmental Protection Agency shall
22378	22378	14 develop a plan to reduce or delay CO2e and copollutant
22379	22379	15 emissions reductions requirements only to the extent and for
22380	22380	16 the duration necessary to meet the resource adequacy and
22381	22381	17 reliability needs of the State, including allowing any plants
22382	22382	18 whose emission reduction deadline has been identified in the
22383	22383	19 plan as creating a reliability concern to continue operating,
22384	22384	20 including operating with reduced emissions or as emergency
22385	22385	21 backup where appropriate. The plan shall also consider the use
22386	22386	22 of renewable energy, energy storage, demand response,
22387	22387	23 transmission development, or other strategies to resolve the
22388	22388	24 identified resource adequacy shortfall or reliability
22389	22389	25 violation.
22390	22390	26 (1) In developing the draft resource plan, the
22391	22391
22392	22392
22393	22393
22394	22394
22395	22395
22396	22396	HB3779 - 623 - LRB104 11172 AAS 21254 b
22397	22397
22398	22398
22399	22399	HB3779- 624 -LRB104 11172 AAS 21254 b HB3779 - 624 - LRB104 11172 AAS 21254 b
22400	22400	HB3779 - 624 - LRB104 11172 AAS 21254 b
22401	22401	1 Environmental Protection Agency and the Illinois Power
22402	22402	2 Agency shall hold at least one workshop open to, and
22403	22403	3 accessible at a time and place convenient to, the public
22404	22404	4 and shall consider any comments made by stakeholders or
22405	22405	5 the public. Upon development of the draft plan, copies of
22406	22406	6 the plan shall be posted and made publicly available on
22407	22407	7 the Environmental Protection Agency's, the Illinois Power
22408	22408	8 Agency's, and the Illinois Commerce Commission's websites.
22409	22409	9 All interested parties shall have 60 days following the
22410	22410	10 date of posting to provide comment to the Environmental
22411	22411	11 Protection Agency and the Illinois Power Agency on the
22412	22412	12 plan. All comments submitted to the Environmental
22413	22413	13 Protection Agency and the Illinois Power Agency shall be
22414	22414	14 encouraged to be specific, supported by data or other
22415	22415	15 detailed analyses, and, if objecting to all or a portion
22416	22416	16 of the plan, accompanied by specific alternative wording
22417	22417	17 or proposals. All comments shall be posted on the
22418	22418	18 Environmental Protection Agency's, the Illinois Power
22419	22419	19 Agency's, and the Illinois Commerce Commission's websites.
22420	22420	20 Within 30 days following the end of the 60-day review
22421	22421	21 period, the Environmental Protection Agency and the
22422	22422	22 Illinois Power Agency shall revise the plan as necessary
22423	22423	23 based on the comments received and file its revised plan
22424	22424	24 with the Illinois Commerce Commission for approval.
22425	22425	25 (2) Within 60 days after the filing of the revised
22426	22426	26 plan at the Illinois Commerce Commission, any person
22427	22427
22428	22428
22429	22429
22430	22430
22431	22431
22432	22432	HB3779 - 624 - LRB104 11172 AAS 21254 b
22433	22433
22434	22434
22435	22435	HB3779- 625 -LRB104 11172 AAS 21254 b HB3779 - 625 - LRB104 11172 AAS 21254 b
22436	22436	HB3779 - 625 - LRB104 11172 AAS 21254 b
22437	22437	1 objecting to the plan shall file an objection with the
22438	22438	2 Illinois Commerce Commission. Within 30 days after the
22439	22439	3 expiration of the comment period, the Illinois Commerce
22440	22440	4 Commission shall determine whether an evidentiary hearing
22441	22441	5 is necessary. The Illinois Commerce Commission shall also
22442	22442	6 host 3 public hearings within 90 days after the plan is
22443	22443	7 filed. Following the evidentiary and public hearings, the
22444	22444	8 Illinois Commerce Commission shall enter its order
22445	22445	9 approving or approving with modifications the reliability
22446	22446	10 mitigation plan within 180 days.
22447	22447	11 (3) The Illinois Commerce Commission shall only
22448	22448	12 approve the plan if the Illinois Commerce Commission
22449	22449	13 determines that it will avoid any and all resolve the
22450	22450	14 resource adequacy or reliability deficiency identified in
22451	22451	15 the reliability mitigation plan at the least amount of CO2e
22452	22452	16 and copollutant emissions, taking into consideration the
22453	22453	17 emissions impacts on environmental justice communities,
22454	22454	18 and that it will ensure adequate, reliable, affordable,
22455	22455	19 efficient, and environmentally sustainable electric
22456	22456	20 service at the lowest total cost over time, taking into
22457	22457	21 account the impact of increases in emissions.
22458	22458	22 (4) If the selected plan and priority resource
22459	22459	23 scenario requires additional renewable energy or energy
22460	22460	24 storage resources than those planned to be procured under
22461	22461	25 the current versions of the Long-Term Renewable Resources
22462	22462	26 Procurement Plan developed under Section 1-75 of the
22463	22463
22464	22464
22465	22465
22466	22466
22467	22467
22468	22468	HB3779 - 625 - LRB104 11172 AAS 21254 b
22469	22469
22470	22470
22471	22471	HB3779- 626 -LRB104 11172 AAS 21254 b HB3779 - 626 - LRB104 11172 AAS 21254 b
22472	22472	HB3779 - 626 - LRB104 11172 AAS 21254 b
22473	22473	1 Illinois Power Agency Act and Section 16-111.5 of the
22474	22474	2 Public Utilities Act, and the Energy Storage Procurement
22475	22475	3 Plan under Section 1-93 of the Illinois Power Agency Act,
22476	22476	4 then the Illinois Power Agency shall propose new
22477	22477	5 procurement targets in those plans that follow the
22478	22478	6 approval of the Clean Resource Plan. The revised plan or
22479	22479	7 plans shall include the additional funds needed to ensure
22480	22480	8 these procurements, and the Illinois Commerce Commission
22481	22481	9 shall approve the additional funds if it finds that the
22482	22482	10 expected long-term cost savings to eligible retail
22483	22483	11 customers from the procurements enabled by the additional
22484	22484	12 funds exceed the additional costs.
22485	22485	13 (5) If the selected plan and priority resource
22486	22486	14 scenario includes a plan to reduce or delay CO2e and
22487	22487	15 copollutant emissions reductions requirements, the
22488	22488	16 Environmental Protection Agency shall delay emissions
22489	22489	17 reductions in Section (i) or Section (k-5) of this
22490	22490	18 Section, as set out in Public Act 102-0662, to the extent
22491	22491	19 required by the selected plan.
22492	22492	20 (6) (4) If the plan includes measures to reduce or
22493	22493	21 delay emission reduction requirements, and if the resource
22494	22494	22 adequacy or reliability deficiency identified in the
22495	22495	23 resource reliability mitigation plan is resolved or
22496	22496	24 reduced, the Environmental Protection Agency and the
22497	22497	25 Illinois Power Agency shall may file an amended plan
22498	22498	26 adjusting the reduction or delay in CO2e and copollutant
22499	22499
22500	22500
22501	22501
22502	22502
22503	22503
22504	22504	HB3779 - 626 - LRB104 11172 AAS 21254 b
22505	22505
22506	22506
22507	22507	HB3779- 627 -LRB104 11172 AAS 21254 b HB3779 - 627 - LRB104 11172 AAS 21254 b
22508	22508	HB3779 - 627 - LRB104 11172 AAS 21254 b
22509	22509	1 emission reduction requirements identified in the plan.
22510	22510	2 (Source: P.A. 102-662, eff. 9-15-21; 102-1031, eff. 5-27-22.)
22511	22511	3 Section 125. The Illinois Highway Code is amended by
22512	22512	4 changing Section 9-113 as follows:
22513	22513	5 (605 ILCS 5/9-113) (from Ch. 121, par. 9-113)
22514	22514	6 Sec. 9-113. (a) No ditches, drains, track, rails, poles,
22515	22515	7 wires, pipe line or other equipment of any public utility
22516	22516	8 company, municipal corporation or other public or private
22517	22517	9 corporation, association or person shall be located, placed or
22518	22518	10 constructed upon, under or along any highway, or upon any
22519	22519	11 township or district road, without first obtaining the written
22520	22520	12 consent of the appropriate highway authority as hereinafter
22521	22521	13 provided for in this Section.
22522	22522	14 (b) The State and county highway authorities are
22523	22523	15 authorized to promulgate reasonable and necessary rules,
22524	22524	16 regulations, and specifications for highways for the
22525	22525	17 administration of this Section. In addition to rules
22526	22526	18 promulgated under this subsection (b), the State highway
22527	22527	19 authority shall and a county highway authority may adopt
22528	22528	20 coordination strategies and practices designed and intended to
22529	22529	21 establish and implement effective communication respecting
22530	22530	22 planned highway projects that the State or county highway
22531	22531	23 authority believes may require removal, relocation, or
22532	22532	24 modification in accordance with subsection (f) of this
22533	22533
22534	22534
22535	22535
22536	22536
22537	22537
22538	22538	HB3779 - 627 - LRB104 11172 AAS 21254 b
22539	22539
22540	22540
22541	22541	HB3779- 628 -LRB104 11172 AAS 21254 b HB3779 - 628 - LRB104 11172 AAS 21254 b
22542	22542	HB3779 - 628 - LRB104 11172 AAS 21254 b
22543	22543	1 Section. The strategies and practices adopted shall include
22544	22544	2 but need not be limited to the delivery of 5 year programs,
22545	22545	3 annual programs, and the establishment of coordination
22546	22546	4 councils in the locales and with the utility participation
22547	22547	5 that will best facilitate and accomplish the requirements of
22548	22548	6 the State and county highway authority acting under subsection
22549	22549	7 (f) of this Section. The utility participation shall include
22550	22550	8 assisting the appropriate highway authority in establishing a
22551	22551	9 schedule for the removal, relocation, or modification of the
22552	22552	10 owner's facilities in accordance with subsection (f) of this
22553	22553	11 Section. In addition, each utility shall designate in writing
22554	22554	12 to the Secretary of Transportation or his or her designee an
22555	22555	13 agent for notice and the delivery of programs. The
22556	22556	14 coordination councils must be established on or before January
22557	22557	15 1, 2002. The 90 day deadline for removal, relocation, or
22558	22558	16 modification of the ditches, drains, track, rails, poles,
22559	22559	17 wires, pipe line, or other equipment in subsection (f) of this
22560	22560	18 Section shall be enforceable upon the establishment of a
22561	22561	19 coordination council in the district or locale where the
22562	22562	20 property in question is located. The coordination councils
22563	22563	21 organized by a county highway authority shall include the
22564	22564	22 county engineer, the County Board Chairman or his or her
22565	22565	23 designee, and with such utility participation as will best
22566	22566	24 facilitate and accomplish the requirements of a highway
22567	22567	25 authority acting under subsection (f) of this Section. Should
22568	22568	26 a county highway authority decide not to establish
22569	22569
22570	22570
22571	22571
22572	22572
22573	22573
22574	22574	HB3779 - 628 - LRB104 11172 AAS 21254 b
22575	22575
22576	22576
22577	22577	HB3779- 629 -LRB104 11172 AAS 21254 b HB3779 - 629 - LRB104 11172 AAS 21254 b
22578	22578	HB3779 - 629 - LRB104 11172 AAS 21254 b
22579	22579	1 coordination councils, the 90 day deadline for removal,
22580	22580	2 relocation, or modification of the ditches, drains, track,
22581	22581	3 rails, poles, wires, pipe line, or other equipment in
22582	22582	4 subsection (f) of this Section shall be waived for those
22583	22583	5 highways.
22584	22584	6 (c) In the case of non-toll federal-aid fully
22585	22585	7 access-controlled State highways, the State highway authority
22586	22586	8 shall not grant consent to the location, placement or
22587	22587	9 construction of ditches, drains, track, rails, poles, wires,
22588	22588	10 pipe line or other equipment upon, under or along any such
22589	22589	11 non-toll federal-aid fully access-controlled State highway,
22590	22590	12 which:
22591	22591	13 (1) would require cutting the pavement structure
22592	22592	14 portion of such highway for installation or, except in the
22593	22593	15 event of an emergency, would require the use of any part of
22594	22594	16 such highway right-of-way for purposes of maintenance or
22595	22595	17 repair. Where, however, the State highway authority
22596	22596	18 determines prior to installation that there is no other
22597	22597	19 access available for maintenance or repair purposes, use
22598	22598	20 by the entity of such highway right-of-way shall be
22599	22599	21 permitted for such purposes in strict accordance with the
22600	22600	22 rules, regulations and specifications of the State highway
22601	22601	23 authority, provided however, that except in the case of
22602	22602	24 access to bridge structures, in no such case shall an
22603	22603	25 entity be permitted access from the through-travel lanes,
22604	22604	26 shoulders or ramps of the non-toll federal-aid fully
22605	22605
22606	22606
22607	22607
22608	22608
22609	22609
22610	22610	HB3779 - 629 - LRB104 11172 AAS 21254 b
22611	22611
22612	22612
22613	22613	HB3779- 630 -LRB104 11172 AAS 21254 b HB3779 - 630 - LRB104 11172 AAS 21254 b
22614	22614	HB3779 - 630 - LRB104 11172 AAS 21254 b
22615	22615	1 access-controlled State highway to maintain or repair its
22616	22616	2 accommodation; or
22617	22617	3 (2) would in the judgment of the State highway
22618	22618	4 authority, endanger or impair any such ditches, drains,
22619	22619	5 track, rails, poles, wires, pipe lines or other equipment
22620	22620	6 already in place; or
22621	22621	7 (3) would, if installed longitudinally within the
22622	22622	8 access control lines of such highway, be above ground
22623	22623	9 after installation except if they are approved pursuant to
22624	22624	10 subsection c-1 that the State highway authority may
22625	22625	11 consent to any above ground installation upon, under or
22626	22626	12 along any bridge, interchange or grade separation within
22627	22627	13 the right-of-way which installation is otherwise in
22628	22628	14 compliance with this Section and any rules, regulations or
22629	22629	15 specifications issued hereunder; or
22630	22630	16 (4) would be inconsistent with Federal law or with
22631	22631	17 rules, regulations or directives of appropriate Federal
22632	22632	18 agencies.
22633	22633	19 (c-1) As used in this subsection, "high voltage
22634	22634	20 transmission line" means an electric line and associated
22635	22635	21 facilities having a design voltage of 100,000 or more. High
22636	22636	22 voltage transmission lines, under the laws of this state or
22637	22637	23 the ordinance of any city or county may be constructed,
22638	22638	24 placed, or maintained within the right of way of any highway,
22639	22639	25 federally aided state highway, controlled access highway,
22640	22640	26 interstate highway, or roadway, except as deemed necessary by
22641	22641
22642	22642
22643	22643
22644	22644
22645	22645
22646	22646	HB3779 - 630 - LRB104 11172 AAS 21254 b
22647	22647
22648	22648
22649	22649	HB3779- 631 -LRB104 11172 AAS 21254 b HB3779 - 631 - LRB104 11172 AAS 21254 b
22650	22650	HB3779 - 631 - LRB104 11172 AAS 21254 b
22651	22651	1 the Secretary of Transportation to protect public safety or
22652	22652	2 ensure the proper function of the highway. If the Secretary of
22653	22653	3 Transportation denies a high voltage electric line co-location
22654	22654	4 request, the reasons for the denial must be submitted for
22655	22655	5 review to the chairs and ranking minority members of the
22656	22656	6 committees with jurisdiction over energy and transportation
22657	22657	7 and the Chair of the Illinois Commerce Commission within 90
22658	22658	8 days of the denial.
22659	22659	9 In the case of co-location of transmission lines with DOT
22660	22660	10 highway right-of-way, the Secretary of Transportation, or
22661	22661	11 their designee, shall, upon written request, engage in
22662	22662	12 coordination activities with a utility or transmission line
22663	22663	13 developer to review requested highway corridors for possible
22664	22664	14 permitted locations of transmission lines. A project
22665	22665	15 coordinator shall be assigned within 30 days of the written
22666	22666	16 request. As part of this consultation, the Department must
22667	22667	17 share all known plans with utilities or developers on
22668	22668	18 potential future projects that could impact the placement of a
22669	22669	19 high voltage transmission line.
22670	22670	20 When a permittable route along a highway corridor has been
22671	22671	21 identified by the Department and the utility or developer, the
22672	22672	22 Department must engage in consultation with the utility or
22673	22673	23 developer to develop a constructability report to be utilized
22674	22674	24 by both parties when colocation projects are being planned and
22675	22675	25 approved. The report must be approved by both parties prior to
22676	22676	26 the Department issuing a permit for use of the highway
22677	22677
22678	22678
22679	22679
22680	22680
22681	22681
22682	22682	HB3779 - 631 - LRB104 11172 AAS 21254 b
22683	22683
22684	22684
22685	22685	HB3779- 632 -LRB104 11172 AAS 21254 b HB3779 - 632 - LRB104 11172 AAS 21254 b
22686	22686	HB3779 - 632 - LRB104 11172 AAS 21254 b
22687	22687	1 right-of-way. The constructability report shall be prepared by
22688	22688	2 the utility or developer in consultation with the Department
22689	22689	3 and shall include the terms and conditions for building the
22690	22690	4 co-located project. Included within the report shall be an
22691	22691	5 agreed upon timeframe for which there will not be any request
22692	22692	6 by The Department for relocation of the transmission line. If
22693	22693	7 the Department needs a transmission line in its right-of-way
22694	22694	8 relocated, it shall give the transmission line owner a 10-year
22695	22695	9 advance notice.
22696	22696	10 (d) In the case of accommodations upon, under or along
22697	22697	11 non-toll federal-aid fully access-controlled State highways
22698	22698	12 the State highway authority may charge an entity reasonable
22699	22699	13 compensation for the right of that entity to longitudinally
22700	22700	14 locate, place or construct ditches, drains, track, rails,
22701	22701	15 poles, wires, pipe line or other equipment upon, under or
22702	22702	16 along such highway. Such compensation may include in-kind
22703	22703	17 compensation.
22704	22704	18 Where the entity applying for use of a non-toll
22705	22705	19 federal-aid fully access-controlled State highway right-of-way
22706	22706	20 is a public utility company, municipal corporation or other
22707	22707	21 public or private corporation, association or person, such
22708	22708	22 compensation shall be based upon but shall not exceed a
22709	22709	23 reasonable estimate by the State highway authority of the fair
22710	22710	24 market value of an easement or leasehold for such use of the
22711	22711	25 highway right-of-way. Where the State highway authority
22712	22712	26 determines that the applied-for use of such highway
22713	22713
22714	22714
22715	22715
22716	22716
22717	22717
22718	22718	HB3779 - 632 - LRB104 11172 AAS 21254 b
22719	22719
22720	22720
22721	22721	HB3779- 633 -LRB104 11172 AAS 21254 b HB3779 - 633 - LRB104 11172 AAS 21254 b
22722	22722	HB3779 - 633 - LRB104 11172 AAS 21254 b
22723	22723	1 right-of-way is for private land uses by an individual and not
22724	22724	2 for commercial purposes, the State highway authority may
22725	22725	3 charge a lesser fee than would be charged a public utility
22726	22726	4 company, municipal corporation or other public or private
22727	22727	5 corporation or association as compensation for the use of the
22728	22728	6 non-toll federal-aid fully access-controlled State highway
22729	22729	7 right-of-way. In no case shall the written consent of the
22730	22730	8 State highway authority give or be construed to give any
22731	22731	9 entity any easement, leasehold or other property interest of
22732	22732	10 any kind in, upon, under, above or along the non-toll
22733	22733	11 federal-aid fully access-controlled State highway
22734	22734	12 right-of-way.
22735	22735	13 Where the compensation from any entity is in whole or in
22736	22736	14 part a fee, such fee may be reasonably set, at the election of
22737	22737	15 the State highway authority, in the form of a single lump sum
22738	22738	16 payment or a schedule of payments. All such fees charged as
22739	22739	17 compensation may be reviewed and adjusted upward by the State
22740	22740	18 highway authority once every 5 years provided that any such
22741	22741	19 adjustment shall be based on changes in the fair market value
22742	22742	20 of an easement or leasehold for such use of the non-toll
22743	22743	21 federal-aid fully access-controlled State highway
22744	22744	22 right-of-way. All such fees received as compensation by the
22745	22745	23 State highway authority shall be deposited in the Road Fund.
22746	22746	24 (e) Any entity applying for consent shall submit such
22747	22747	25 information in such form and detail to the appropriate highway
22748	22748	26 authority as to allow the authority to evaluate the entity's
22749	22749
22750	22750
22751	22751
22752	22752
22753	22753
22754	22754	HB3779 - 633 - LRB104 11172 AAS 21254 b
22755	22755
22756	22756
22757	22757	HB3779- 634 -LRB104 11172 AAS 21254 b HB3779 - 634 - LRB104 11172 AAS 21254 b
22758	22758	HB3779 - 634 - LRB104 11172 AAS 21254 b
22759	22759	1 application. In the case of accommodations upon, under or
22760	22760	2 along non-toll federal-aid fully access-controlled State
22761	22761	3 highways the entity applying for such consent shall reimburse
22762	22762	4 the State highway authority for all of the authority's
22763	22763	5 reasonable expenses in evaluating that entity's application,
22764	22764	6 including but not limited to engineering and legal fees.
22765	22765	7 (f) Any ditches, drains, track, rails, poles, wires, pipe
22766	22766	8 line, or other equipment located, placed, or constructed upon,
22767	22767	9 under, or along a highway with the consent of the State or
22768	22768	10 county highway authority under this Section shall, upon
22769	22769	11 written notice by the State or county highway authority be
22770	22770	12 removed, relocated, or modified by the owner, the owner's
22771	22771	13 agents, contractors, or employees at no expense to the State
22772	22772	14 or county highway authority when and as deemed necessary by
22773	22773	15 the State or county highway authority for highway or highway
22774	22774	16 safety purposes. The notice shall be properly given after the
22775	22775	17 completion of engineering plans, the receipt of the necessary
22776	22776	18 permits issued by the appropriate State and county highway
22777	22777	19 authority to begin work, and the establishment of sufficient
22778	22778	20 rights-of-way for a given utility authorized by the State or
22779	22779	21 county highway authority to remain on the highway right-of-way
22780	22780	22 such that the unit of local government or other owner of any
22781	22781	23 facilities receiving notice in accordance with this subsection
22782	22782	24 (f) can proceed with relocating, replacing, or reconstructing
22783	22783	25 the ditches, drains, track, rails, poles, wires, pipe line, or
22784	22784	26 other equipment. If a permit application to relocate on a
22785	22785
22786	22786
22787	22787
22788	22788
22789	22789
22790	22790	HB3779 - 634 - LRB104 11172 AAS 21254 b
22791	22791
22792	22792
22793	22793	HB3779- 635 -LRB104 11172 AAS 21254 b HB3779 - 635 - LRB104 11172 AAS 21254 b
22794	22794	HB3779 - 635 - LRB104 11172 AAS 21254 b
22795	22795	1 public right-of-way is not filed within 15 days of the receipt
22796	22796	2 of final engineering plans, the notice precondition of a
22797	22797	3 permit to begin work is waived. However, under no
22798	22798	4 circumstances shall this notice provision be construed to
22799	22799	5 require the State or any government department or agency to
22800	22800	6 purchase additional rights-of-way to accommodate utilities.
22801	22801	7 If, within 90 days after receipt of such written notice, the
22802	22802	8 ditches, drains, track, rails, poles, wires, pipe line, or
22803	22803	9 other equipment have not been removed, relocated, or modified
22804	22804	10 to the reasonable satisfaction of the State or county highway
22805	22805	11 authority, or if arrangements are not made satisfactory to the
22806	22806	12 State or county highway authority for such removal,
22807	22807	13 relocation, or modification, the State or county highway
22808	22808	14 authority may remove, relocate, or modify such ditches,
22809	22809	15 drains, track, rails, poles, wires, pipe line, or other
22810	22810	16 equipment and bill the owner thereof for the total cost of such
22811	22811	17 removal, relocation, or modification. The scope of the project
22812	22812	18 shall be taken into consideration by the State or county
22813	22813	19 highway authority in determining satisfactory arrangements.
22814	22814	20 The State or county highway authority shall determine the
22815	22815	21 terms of payment of those costs provided that all costs billed
22816	22816	22 by the State or county highway authority shall not be made
22817	22817	23 payable over more than a 5 year period from the date of
22818	22818	24 billing. The State and county highway authority shall have the
22819	22819	25 power to extend the time of payment in cases of demonstrated
22820	22820	26 financial hardship by a unit of local government or other
22821	22821
22822	22822
22823	22823
22824	22824
22825	22825
22826	22826	HB3779 - 635 - LRB104 11172 AAS 21254 b
22827	22827
22828	22828
22829	22829	HB3779- 636 -LRB104 11172 AAS 21254 b HB3779 - 636 - LRB104 11172 AAS 21254 b
22830	22830	HB3779 - 636 - LRB104 11172 AAS 21254 b
22831	22831	1 public owner of any facilities removed, relocated, or modified
22832	22832	2 from the highway right-of-way in accordance with this
22833	22833	3 subsection (f). This paragraph shall not be construed to
22834	22834	4 prohibit the State or county highway authority from paying any
22835	22835	5 part of the cost of removal, relocation, or modification where
22836	22836	6 such payment is otherwise provided for by State or federal
22837	22837	7 statute or regulation. At any time within 90 days after
22838	22838	8 written notice was given, the owner of the drains, track,
22839	22839	9 rails, poles, wires, pipe line, or other equipment may request
22840	22840	10 the district engineer or, if appropriate, the county engineer
22841	22841	11 for a waiver of the 90 day deadline. The appropriate district
22842	22842	12 or county engineer shall make a decision concerning waiver
22843	22843	13 within 10 days of receipt of the request and may waive the 90
22844	22844	14 day deadline if he or she makes a written finding as to the
22845	22845	15 reasons for waiving the deadline. Reasons for waiving the
22846	22846	16 deadline shall be limited to acts of God, war, the scope of the
22847	22847	17 project, the State failing to follow the proper notice
22848	22848	18 procedure, and any other cause beyond reasonable control of
22849	22849	19 the owner of the facilities. Waiver must not be unreasonably
22850	22850	20 withheld. If 90 days after written notice was given, the
22851	22851	21 ditches, drains, track, rails, poles, wires, pipe line, or
22852	22852	22 other equipment have not been removed, relocated, or modified
22853	22853	23 to the satisfaction of the State or county highway authority,
22854	22854	24 no waiver of deadline has been requested or issued by the
22855	22855	25 appropriate district or county engineer, and no satisfactory
22856	22856	26 arrangement has been made with the appropriate State or county
22857	22857
22858	22858
22859	22859
22860	22860
22861	22861
22862	22862	HB3779 - 636 - LRB104 11172 AAS 21254 b
22863	22863
22864	22864
22865	22865	HB3779- 637 -LRB104 11172 AAS 21254 b HB3779 - 637 - LRB104 11172 AAS 21254 b
22866	22866	HB3779 - 637 - LRB104 11172 AAS 21254 b
22867	22867	1 highway authority, the State or county highway authority or
22868	22868	2 the general contractor of the building project may file a
22869	22869	3 complaint in the circuit court for an emergency order to
22870	22870	4 direct and compel the owner to remove, relocate, or modify the
22871	22871	5 drains, track, rails, poles, wires, pipe line, or other
22872	22872	6 equipment to the satisfaction of the appropriate highway
22873	22873	7 authority. The complaint for an order shall be brought in the
22874	22874	8 circuit in which the subject matter of the complaint is
22875	22875	9 situated or, if the subject matter of the complaint is
22876	22876	10 situated in more than one circuit, in any one of those
22877	22877	11 circuits.
22878	22878	12 (g) It shall be the sole responsibility of the entity,
22879	22879	13 without expense to the State highway authority, to maintain
22880	22880	14 and repair its ditches, drains, track, rails, poles, wires,
22881	22881	15 pipe line or other equipment after it is located, placed or
22882	22882	16 constructed upon, under or along any State highway and in no
22883	22883	17 case shall the State highway authority thereafter be liable or
22884	22884	18 responsible to the entity for any damages or liability of any
22885	22885	19 kind whatsoever incurred by the entity or to the entity's
22886	22886	20 ditches, drains, track, rails, poles, wires, pipe line or
22887	22887	21 other equipment.
22888	22888	22 (h) Except as provided in subsection (h-1), upon receipt
22889	22889	23 of an application therefor, consent to so use a highway may be
22890	22890	24 granted subject to such terms and conditions not inconsistent
22891	22891	25 with this Code as the highway authority deems for the best
22892	22892	26 interest of the public. The terms and conditions required by
22893	22893
22894	22894
22895	22895
22896	22896
22897	22897
22898	22898	HB3779 - 637 - LRB104 11172 AAS 21254 b
22899	22899
22900	22900
22901	22901	HB3779- 638 -LRB104 11172 AAS 21254 b HB3779 - 638 - LRB104 11172 AAS 21254 b
22902	22902	HB3779 - 638 - LRB104 11172 AAS 21254 b
22903	22903	1 the appropriate highway authority may include but need not be
22904	22904	2 limited to participation by the party granted consent in the
22905	22905	3 strategies and practices adopted under subsection (b) of this
22906	22906	4 Section. The petitioner shall pay to the owners of property
22907	22907	5 abutting upon the affected highways established as though by
22908	22908	6 common law plat all damages the owners may sustain by reason of
22909	22909	7 such use of the highway, such damages to be ascertained and
22910	22910	8 paid in the manner provided by law for the exercise of the
22911	22911	9 right of eminent domain.
22912	22912	10 (h-1) With regard to any public utility, as defined in
22913	22913	11 Section 3-105 of the Public Utilities Act, engaged in public
22914	22914	12 water or public sanitary sewer service that comes under the
22915	22915	13 jurisdiction of the Illinois Commerce Commission, upon receipt
22916	22916	14 of an application therefor, consent to so use a highway may be
22917	22917	15 granted subject to such terms and conditions not inconsistent
22918	22918	16 with this Code as the highway authority deems for the best
22919	22919	17 interest of the public. The terms and conditions required by
22920	22920	18 the appropriate highway authority may include but need not be
22921	22921	19 limited to participation by the party granted consent in the
22922	22922	20 strategies and practices adopted under subsection (b) of this
22923	22923	21 Section. If the highway authority does not have fee ownership
22924	22924	22 of the property, the petitioner shall pay to the owners of
22925	22925	23 property located in the highway right-of-way all damages the
22926	22926	24 owners may sustain by reason of such use of the highway, such
22927	22927	25 damages to be ascertained and paid in the manner provided by
22928	22928	26 law for the exercise of the right of eminent domain. The
22929	22929
22930	22930
22931	22931
22932	22932
22933	22933
22934	22934	HB3779 - 638 - LRB104 11172 AAS 21254 b
22935	22935
22936	22936
22937	22937	HB3779- 639 -LRB104 11172 AAS 21254 b HB3779 - 639 - LRB104 11172 AAS 21254 b
22938	22938	HB3779 - 639 - LRB104 11172 AAS 21254 b
22939	22939	1 consent shall not otherwise relieve the entity granted that
22940	22940	2 consent from obtaining by purchase, condemnation, or otherwise
22941	22941	3 the necessary approval of any owner of the fee over or under
22942	22942	4 which the highway or road is located, except to the extent that
22943	22943	5 no such owner has paid real estate taxes on the property for
22944	22944	6 the 2 years prior to the grant of the consent. Owners of
22945	22945	7 property that abuts the right-of-way but who acquired the
22946	22946	8 property through a conveyance that either expressly excludes
22947	22947	9 the property subject to the right-of-way or that describes the
22948	22948	10 property conveyed as ending at the right-of-way or being
22949	22949	11 bounded by the right-of-way or road shall not be considered
22950	22950	12 owners of property located in the right-of-way and shall not
22951	22951	13 be entitled to damages by reason of the use of the highway or
22952	22952	14 road for utility purposes, except that this provision shall
22953	22953	15 not relieve the public utility from the obligation to pay for
22954	22954	16 any physical damage it causes to improvements lawfully located
22955	22955	17 in the right-of-way. Owners of abutting property whose
22956	22956	18 descriptions include the right-of-way but are made subject to
22957	22957	19 the right-of-way shall be entitled to compensation for use of
22958	22958	20 the right-of-way. If the property subject to the right-of-way
22959	22959	21 is not owned by the owners of the abutting property (either
22960	22960	22 because it is expressly excluded from the property conveyed to
22961	22961	23 an abutting property owner or the property as conveyed ends at
22962	22962	24 or is bounded by the right-of-way or road), then the
22963	22963	25 petitioner shall pay any damages, as so calculated, to the
22964	22964	26 person or persons who have paid real estate taxes for the
22965	22965
22966	22966
22967	22967
22968	22968
22969	22969
22970	22970	HB3779 - 639 - LRB104 11172 AAS 21254 b
22971	22971
22972	22972
22973	22973	HB3779- 640 -LRB104 11172 AAS 21254 b HB3779 - 640 - LRB104 11172 AAS 21254 b
22974	22974	HB3779 - 640 - LRB104 11172 AAS 21254 b
22975	22975	1 property as reflected in the county tax records. If no person
22976	22976	2 has paid real estate taxes, then the public interest permits
22977	22977	3 the installation of the facilities without payment of any
22978	22978	4 damages. This provision of this amendatory Act of the 93rd
22979	22979	5 General Assembly is intended to clarify, by codification,
22980	22980	6 existing law and is not intended to change the law.
22981	22981	7 (i) Such consent shall be granted by the Department in the
22982	22982	8 case of a State highway; by the county board or its designated
22983	22983	9 county superintendent of highways in the case of a county
22984	22984	10 highway; by either the highway commissioner or the county
22985	22985	11 superintendent of highways in the case of a township or
22986	22986	12 district road, provided that if consent is granted by the
22987	22987	13 highway commissioner, the petition shall be filed with the
22988	22988	14 commissioner at least 30 days prior to the proposed date of the
22989	22989	15 beginning of construction, and that if written consent is not
22990	22990	16 given by the commissioner within 30 days after receipt of the
22991	22991	17 petition, the applicant may make written application to the
22992	22992	18 county superintendent of highways for consent to the
22993	22993	19 construction. In the case of township roads, the county
22994	22994	20 superintendent of highways may either grant consent for the
22995	22995	21 construction or deny the application. The county
22996	22996	22 superintendent of highways shall provide written confirmation,
22997	22997	23 citing the basis of the decision, to both the highway
22998	22998	24 commissioner and the applicant. This Section does not vitiate,
22999	22999	25 extend or otherwise affect any consent granted in accordance
23000	23000	26 with law prior to the effective date of this Code to so use any
23001	23001
23002	23002
23003	23003
23004	23004
23005	23005
23006	23006	HB3779 - 640 - LRB104 11172 AAS 21254 b
23007	23007
23008	23008
23009	23009	HB3779- 641 -LRB104 11172 AAS 21254 b HB3779 - 641 - LRB104 11172 AAS 21254 b
23010	23010	HB3779 - 641 - LRB104 11172 AAS 21254 b
23011	23011	1 highway.
23012	23012	2 (j) Nothing in this Section shall limit the right of a
23013	23013	3 highway authority to permit the location, placement or
23014	23014	4 construction or any ditches, drains, track, rails, poles,
23015	23015	5 wires, pipe line or other equipment upon, under or along any
23016	23016	6 highway or road as a part of its highway or road facilities or
23017	23017	7 which the highway authority determines is necessary to service
23018	23018	8 facilities required for operating the highway or road,
23019	23019	9 including rest areas and weigh stations.
23020	23020	10 (k) Paragraphs (c) and (d) of this Section shall not apply
23021	23021	11 to any accommodation located, placed or constructed with the
23022	23022	12 consent of the State highway authority upon, under or along
23023	23023	13 any non-toll federal-aid fully access-controlled State highway
23024	23024	14 prior to July 1, 1984, provided that accommodation was
23025	23025	15 otherwise in compliance with the rules, regulations and
23026	23026	16 specifications of the State highway authority.
23027	23027	17 (l) Except as provided in subsection (l-1), the consent to
23028	23028	18 be granted pursuant to this Section by the appropriate highway
23029	23029	19 authority shall be effective only to the extent of the
23030	23030	20 property interest of the State or government unit served by
23031	23031	21 that highway authority. Such consent shall not be binding on
23032	23032	22 any owner of the fee over or under which the highway or road is
23033	23033	23 located and shall not otherwise relieve the entity granted
23034	23034	24 that consent from obtaining by purchase, condemnation or
23035	23035	25 otherwise the necessary approval of any owner of the fee over
23036	23036	26 or under which the highway or road is located. This paragraph
23037	23037
23038	23038
23039	23039
23040	23040
23041	23041
23042	23042	HB3779 - 641 - LRB104 11172 AAS 21254 b
23043	23043
23044	23044
23045	23045	HB3779- 642 -LRB104 11172 AAS 21254 b HB3779 - 642 - LRB104 11172 AAS 21254 b
23046	23046	HB3779 - 642 - LRB104 11172 AAS 21254 b
23047	23047	1 shall not be construed as a limitation on the use for highway
23048	23048	2 or road purposes of the land or other property interests
23049	23049	3 acquired by the public for highway or road purposes, including
23050	23050	4 the space under or above such right-of-way.
23051	23051	5 (l-1) With regard to any public utility, as defined in
23052	23052	6 Section 3-105 of the Public Utilities Act, engaged in public
23053	23053	7 water or public sanitary sewer service that comes under the
23054	23054	8 jurisdiction of the Illinois Commerce Commission, the consent
23055	23055	9 to be granted pursuant to this Section by the appropriate
23056	23056	10 highway authority shall be effective only to the extent of the
23057	23057	11 property interest of the State or government unit served by
23058	23058	12 that highway authority. Such consent shall not be binding on
23059	23059	13 any owner of the fee over or under which the highway or road is
23060	23060	14 located but shall be binding on any abutting property owner
23061	23061	15 whose property boundary ends at the right-of-way of the
23062	23062	16 highway or road. For purposes of the preceding sentence,
23063	23063	17 property that includes a portion of a highway or road but is
23064	23064	18 subject to the highway or road shall not be considered to end
23065	23065	19 at the highway or road. The consent shall not otherwise
23066	23066	20 relieve the entity granted that consent from obtaining by
23067	23067	21 purchase, condemnation or otherwise the necessary approval of
23068	23068	22 any owner of the fee over or under which the highway or road is
23069	23069	23 located, except to the extent that no such owner has paid real
23070	23070	24 estate taxes on the property for the 2 years prior to the grant
23071	23071	25 of the consent. This provision is not intended to absolve a
23072	23072	26 utility from obtaining consent from a lawful owner of the
23073	23073
23074	23074
23075	23075
23076	23076
23077	23077
23078	23078	HB3779 - 642 - LRB104 11172 AAS 21254 b
23079	23079
23080	23080
23081	23081	HB3779- 643 -LRB104 11172 AAS 21254 b HB3779 - 643 - LRB104 11172 AAS 21254 b
23082	23082	HB3779 - 643 - LRB104 11172 AAS 21254 b
23083	23083	1 roadway or highway property (i.e. a person whose deed of
23084	23084	2 conveyance lawfully includes the property, whether or not made
23085	23085	3 subject to the highway or road) but who does not pay taxes by
23086	23086	4 reason of Division 6 of Article 10 of the Property Tax Code.
23087	23087	5 This paragraph shall not be construed as a limitation on the
23088	23088	6 use for highway or road purposes of the land or other property
23089	23089	7 interests acquired by the public for highway or road purposes,
23090	23090	8 including the space under or above such right-of-way.
23091	23091	9 (m) The provisions of this Section apply to all permits
23092	23092	10 issued by the Department of Transportation and the appropriate
23093	23093	11 State or county highway authority.
23094	23094	12 (Source: P.A. 102-449, eff. 1-1-22.)
23095	23095	13 Section 130. The Eminent Domain Act is amended by changing
23096	23096	14 Section 5-5-5 as follows:
23097	23097	15 (735 ILCS 30/5-5-5)
23098	23098	16 Sec. 5-5-5. Exercise of the power of eminent domain;
23099	23099	17 public use; blight.
23100	23100	18 (a) In addition to all other limitations and requirements,
23101	23101	19 a condemning authority may not take or damage property by the
23102	23102	20 exercise of the power of eminent domain unless it is for a
23103	23103	21 public use, as set forth in this Section.
23104	23104	22 (a-5) Subsections (b), (c), (d), (e), and (f) of this
23105	23105	23 Section do not apply to the acquisition of property under the
23106	23106	24 O'Hare Modernization Act. A condemning authority may exercise
23107	23107
23108	23108
23109	23109
23110	23110
23111	23111
23112	23112	HB3779 - 643 - LRB104 11172 AAS 21254 b
23113	23113
23114	23114
23115	23115	HB3779- 644 -LRB104 11172 AAS 21254 b HB3779 - 644 - LRB104 11172 AAS 21254 b
23116	23116	HB3779 - 644 - LRB104 11172 AAS 21254 b
23117	23117	1 the power of eminent domain for the acquisition or damaging of
23118	23118	2 property under the O'Hare Modernization Act as provided for by
23119	23119	3 law in effect prior to the effective date of this Act.
23120	23120	4 (a-10) Subsections (b), (c), (d), (e), and (f) of this
23121	23121	5 Section do not apply to the acquisition or damaging of
23122	23122	6 property in furtherance of the goals and objectives of an
23123	23123	7 existing tax increment allocation redevelopment plan. A
23124	23124	8 condemning authority may exercise the power of eminent domain
23125	23125	9 for the acquisition of property in furtherance of an existing
23126	23126	10 tax increment allocation redevelopment plan as provided for by
23127	23127	11 law in effect prior to the effective date of this Act.
23128	23128	12 As used in this subsection, "existing tax increment
23129	23129	13 allocation redevelopment plan" means a redevelopment plan that
23130	23130	14 was adopted under the Tax Increment Allocation Redevelopment
23131	23131	15 Act (Article 11, Division 74.4 of the Illinois Municipal Code)
23132	23132	16 prior to April 15, 2006 and for which property assembly costs
23133	23133	17 were, before that date, included as a budget line item in the
23134	23134	18 plan or described in the narrative portion of the plan as part
23135	23135	19 of the redevelopment project, but does not include (i) any
23136	23136	20 additional area added to the redevelopment project area on or
23137	23137	21 after April 15, 2006, (ii) any subsequent extension of the
23138	23138	22 completion date of a redevelopment plan beyond the estimated
23139	23139	23 completion date established in that plan prior to April 15,
23140	23140	24 2006, (iii) any acquisition of property in a conservation area
23141	23141	25 for which the condemnation complaint is filed more than 12
23142	23142	26 years after the effective date of this Act, or (iv) any
23143	23143
23144	23144
23145	23145
23146	23146
23147	23147
23148	23148	HB3779 - 644 - LRB104 11172 AAS 21254 b
23149	23149
23150	23150
23151	23151	HB3779- 645 -LRB104 11172 AAS 21254 b HB3779 - 645 - LRB104 11172 AAS 21254 b
23152	23152	HB3779 - 645 - LRB104 11172 AAS 21254 b
23153	23153	1 acquisition of property in an industrial park conservation
23154	23154	2 area.
23155	23155	3 As used in this subsection, "conservation area" and
23156	23156	4 "industrial park conservation area" have the same meanings as
23157	23157	5 under Section 11-74.4-3 of the Illinois Municipal Code.
23158	23158	6 (b) If the exercise of eminent domain authority is to
23159	23159	7 acquire property for public ownership and control, then the
23160	23160	8 condemning authority must prove that (i) the acquisition of
23161	23161	9 the property is necessary for a public purpose and (ii) the
23162	23162	10 acquired property will be owned and controlled by the
23163	23163	11 condemning authority or another governmental entity.
23164	23164	12 (c) Except when the acquisition is governed by subsection
23165	23165	13 (b) or is primarily for one of the purposes specified in
23166	23166	14 subsection (d), (e), or (f) and the condemning authority
23167	23167	15 elects to proceed under one of those subsections, if the
23168	23168	16 exercise of eminent domain authority is to acquire property
23169	23169	17 for private ownership or control, or both, then the condemning
23170	23170	18 authority must prove by clear and convincing evidence that the
23171	23171	19 acquisition of the property for private ownership or control
23172	23172	20 is (i) primarily for the benefit, use, or enjoyment of the
23173	23173	21 public and (ii) necessary for a public purpose.
23174	23174	22 An acquisition of property primarily for the purpose of
23175	23175	23 the elimination of blight is rebuttably presumed to be for a
23176	23176	24 public purpose and primarily for the benefit, use, or
23177	23177	25 enjoyment of the public under this subsection.
23178	23178	26 Any challenge to the existence of blighting factors
23179	23179
23180	23180
23181	23181
23182	23182
23183	23183
23184	23184	HB3779 - 645 - LRB104 11172 AAS 21254 b
23185	23185
23186	23186
23187	23187	HB3779- 646 -LRB104 11172 AAS 21254 b HB3779 - 646 - LRB104 11172 AAS 21254 b
23188	23188	HB3779 - 646 - LRB104 11172 AAS 21254 b
23189	23189	1 alleged in a complaint to condemn under this subsection shall
23190	23190	2 be raised within 6 months of the filing date of the complaint
23191	23191	3 to condemn, and if not raised within that time the right to
23192	23192	4 challenge the existence of those blighting factors shall be
23193	23193	5 deemed waived.
23194	23194	6 Evidence that the Illinois Commerce Commission has granted
23195	23195	7 a certificate or otherwise made a finding of public
23196	23196	8 convenience and necessity for an acquisition of property (or
23197	23197	9 any right or interest in property) for private ownership or
23198	23198	10 control (including, without limitation, an acquisition for
23199	23199	11 which the use of eminent domain is authorized under the Public
23200	23200	12 Utilities Act, the Telephone Company Act, or the Electric
23201	23201	13 Supplier Act) to be used for utility purposes creates a
23202	23202	14 rebuttable presumption that such acquisition of that property
23203	23203	15 (or right or interest in property) is (i) primarily for the
23204	23204	16 benefit, use, or enjoyment of the public and (ii) necessary
23205	23205	17 for a public purpose.
23206	23206	18 In the case of an acquisition of property (or any right or
23207	23207	19 interest in property) for private ownership or control to be
23208	23208	20 used for utility, pipeline, or railroad purposes for which no
23209	23209	21 certificate or finding of public convenience and necessity by
23210	23210	22 the Illinois Commerce Commission is required, evidence that
23211	23211	23 the acquisition is one for which the use of eminent domain is
23212	23212	24 authorized under one of the following laws creates a
23213	23213	25 rebuttable presumption that the acquisition of that property
23214	23214	26 (or right or interest in property) is (i) primarily for the
23215	23215
23216	23216
23217	23217
23218	23218
23219	23219
23220	23220	HB3779 - 646 - LRB104 11172 AAS 21254 b
23221	23221
23222	23222
23223	23223	HB3779- 647 -LRB104 11172 AAS 21254 b HB3779 - 647 - LRB104 11172 AAS 21254 b
23224	23224	HB3779 - 647 - LRB104 11172 AAS 21254 b
23225	23225	1 benefit, use, or enjoyment of the public and (ii) necessary
23226	23226	2 for a public purpose:
23227	23227	3 (1) the Public Utilities Act,
23228	23228	4 (2) the Telephone Company Act,
23229	23229	5 (3) the Electric Supplier Act,
23230	23230	6 (4) the Railroad Terminal Authority Act,
23231	23231	7 (5) the Grand Avenue Railroad Relocation Authority
23232	23232	8 Act,
23233	23233	9 (6) the West Cook Railroad Relocation and Development
23234	23234	10 Authority Act,
23235	23235	11 (7) Section 4-505 of the Illinois Highway Code,
23236	23236	12 (8) Section 17 or 18 of the Railroad Incorporation
23237	23237	13 Act,
23238	23238	14 (9) Section 18c-7501 of the Illinois Vehicle Code.
23239	23239	15 (d) If the exercise of eminent domain authority is to
23240	23240	16 acquire property for private ownership or control and if the
23241	23241	17 primary basis for the acquisition is the elimination of blight
23242	23242	18 and the condemning authority elects to proceed under this
23243	23243	19 subsection, then the condemning authority must: (i) prove by a
23244	23244	20 preponderance of the evidence that acquisition of the property
23245	23245	21 for private ownership or control is necessary for a public
23246	23246	22 purpose; (ii) prove by a preponderance of the evidence that
23247	23247	23 the property to be acquired is located in an area that is
23248	23248	24 currently designated as a blighted area or conservation area
23249	23249	25 under an applicable statute; (iii) if the existence of blight
23250	23250	26 or blighting factors is challenged in an appropriate motion
23251	23251
23252	23252
23253	23253
23254	23254
23255	23255
23256	23256	HB3779 - 647 - LRB104 11172 AAS 21254 b
23257	23257
23258	23258
23259	23259	HB3779- 648 -LRB104 11172 AAS 21254 b HB3779 - 648 - LRB104 11172 AAS 21254 b
23260	23260	HB3779 - 648 - LRB104 11172 AAS 21254 b
23261	23261	1 filed within 6 months after the date of filing of the complaint
23262	23262	2 to condemn, prove by a preponderance of the evidence that the
23263	23263	3 required blighting factors existed in the area so designated
23264	23264	4 (but not necessarily in the particular property to be
23265	23265	5 acquired) at the time of the designation under item (ii) or at
23266	23266	6 any time thereafter; and (iv) prove by a preponderance of the
23267	23267	7 evidence at least one of the following:
23268	23268	8 (A) that it has entered into an express written
23269	23269	9 agreement in which a private person or entity agrees to
23270	23270	10 undertake a development project within the blighted area
23271	23271	11 that specifically details the reasons for which the
23272	23272	12 property or rights in that property are necessary for the
23273	23273	13 development project;
23274	23274	14 (B) that the exercise of eminent domain power and the
23275	23275	15 proposed use of the property by the condemning authority
23276	23276	16 are consistent with a regional plan that has been adopted
23277	23277	17 within the past 5 years in accordance with Section 5-14001
23278	23278	18 of the Counties Code or Section 11-12-6 of the Illinois
23279	23279	19 Municipal Code or with a local land resource management
23280	23280	20 plan adopted under Section 4 of the Local Land Resource
23281	23281	21 Management Planning Act; or
23282	23282	22 (C) that (1) the acquired property will be used in the
23283	23283	23 development of a project that is consistent with the land
23284	23284	24 uses set forth in a comprehensive redevelopment plan
23285	23285	25 prepared in accordance with the applicable statute
23286	23286	26 authorizing the condemning authority to exercise the power
23287	23287
23288	23288
23289	23289
23290	23290
23291	23291
23292	23292	HB3779 - 648 - LRB104 11172 AAS 21254 b
23293	23293
23294	23294
23295	23295	HB3779- 649 -LRB104 11172 AAS 21254 b HB3779 - 649 - LRB104 11172 AAS 21254 b
23296	23296	HB3779 - 649 - LRB104 11172 AAS 21254 b
23297	23297	1 of eminent domain and is consistent with the goals and
23298	23298	2 purposes of that comprehensive redevelopment plan, and (2)
23299	23299	3 an enforceable written agreement, deed restriction, or
23300	23300	4 similar encumbrance has been or will be executed and
23301	23301	5 recorded against the acquired property to assure that the
23302	23302	6 project and the use of the property remain consistent with
23303	23303	7 those land uses, goals, and purposes for a period of at
23304	23304	8 least 40 years, which execution and recording shall be
23305	23305	9 included as a requirement in any final order entered in
23306	23306	10 the condemnation proceeding.
23307	23307	11 The existence of an ordinance, resolution, or other
23308	23308	12 official act designating an area as blighted is not prima
23309	23309	13 facie evidence of the existence of blight. A finding by the
23310	23310	14 court in a condemnation proceeding that a property or area has
23311	23311	15 not been proven to be blighted does not apply to any other case
23312	23312	16 or undermine the designation of a blighted area or
23313	23313	17 conservation area or the determination of the existence of
23314	23314	18 blight for any other purpose or under any other statute,
23315	23315	19 including without limitation under the Tax Increment
23316	23316	20 Allocation Redevelopment Act (Article 11, Division 74.4 of the
23317	23317	21 Illinois Municipal Code).
23318	23318	22 Any challenge to the existence of blighting factors
23319	23319	23 alleged in a complaint to condemn under this subsection shall
23320	23320	24 be raised within 6 months of the filing date of the complaint
23321	23321	25 to condemn, and if not raised within that time the right to
23322	23322	26 challenge the existence of those blighting factors shall be
23323	23323
23324	23324
23325	23325
23326	23326
23327	23327
23328	23328	HB3779 - 649 - LRB104 11172 AAS 21254 b
23329	23329
23330	23330
23331	23331	HB3779- 650 -LRB104 11172 AAS 21254 b HB3779 - 650 - LRB104 11172 AAS 21254 b
23332	23332	HB3779 - 650 - LRB104 11172 AAS 21254 b
23333	23333	1 deemed waived.
23334	23334	2 (e) If the exercise of eminent domain authority is to
23335	23335	3 acquire property for private ownership or control and if the
23336	23336	4 primary purpose of the acquisition is one of the purposes
23337	23337	5 specified in item (iii) of this subsection and the condemning
23338	23338	6 authority elects to proceed under this subsection, then the
23339	23339	7 condemning authority must prove by a preponderance of the
23340	23340	8 evidence that: (i) the acquisition of the property is
23341	23341	9 necessary for a public purpose; (ii) an enforceable written
23342	23342	10 agreement, deed restriction, or similar encumbrance has been
23343	23343	11 or will be executed and recorded against the acquired property
23344	23344	12 to assure that the project and the use of the property remain
23345	23345	13 consistent with the applicable purpose specified in item (iii)
23346	23346	14 of this subsection for a period of at least 40 years, which
23347	23347	15 execution and recording shall be included as a requirement in
23348	23348	16 any final order entered in the condemnation proceeding; and
23349	23349	17 (iii) the acquired property will be one of the following:
23350	23350	18 (1) included in the project site for a residential
23351	23351	19 project, or a mixed-use project including residential
23352	23352	20 units, where not less than 20% of the residential units in
23353	23353	21 the project are made available, for at least 15 years, by
23354	23354	22 deed restriction, long-term lease, regulatory agreement,
23355	23355	23 extended use agreement, or a comparable recorded
23356	23356	24 encumbrance, to low-income households and very low-income
23357	23357	25 households, as defined in Section 3 of the Illinois
23358	23358	26 Affordable Housing Act;
23359	23359
23360	23360
23361	23361
23362	23362
23363	23363
23364	23364	HB3779 - 650 - LRB104 11172 AAS 21254 b
23365	23365
23366	23366
23367	23367	HB3779- 651 -LRB104 11172 AAS 21254 b HB3779 - 651 - LRB104 11172 AAS 21254 b
23368	23368	HB3779 - 651 - LRB104 11172 AAS 21254 b
23369	23369	1 (2) used primarily for public airport, road, parking,
23370	23370	2 or mass transportation purposes and sold or leased to a
23371	23371	3 private party in a sale-leaseback, lease-leaseback, or
23372	23372	4 similar structured financing;
23373	23373	5 (3) owned or used by a public utility or electric
23374	23374	6 cooperative for utility purposes;
23375	23375	7 (4) owned or used by a railroad for passenger or
23376	23376	8 freight transportation purposes;
23377	23377	9 (5) sold or leased to a private party that operates a
23378	23378	10 water supply, waste water, recycling, waste disposal,
23379	23379	11 waste-to-energy, or similar facility;
23380	23380	12 (6) sold or leased to a not-for-profit corporation
23381	23381	13 whose purposes include the preservation of open space, the
23382	23382	14 operation of park space, and similar public purposes;
23383	23383	15 (7) used as a library, museum, or related facility, or
23384	23384	16 as infrastructure related to such a facility;
23385	23385	17 (8) used by a private party for the operation of a
23386	23386	18 charter school open to the general public; or
23387	23387	19 (9) a historic resource, as defined in Section 3 of
23388	23388	20 the Illinois State Agency Historic Resources Preservation
23389	23389	21 Act, a landmark designated as such under a local
23390	23390	22 ordinance, or a contributing structure within a local
23391	23391	23 landmark district listed on the National Register of
23392	23392	24 Historic Places, that is being acquired for purposes of
23393	23393	25 preservation or rehabilitation.
23394	23394	26 (f) If the exercise of eminent domain authority is to
23395	23395
23396	23396
23397	23397
23398	23398
23399	23399
23400	23400	HB3779 - 651 - LRB104 11172 AAS 21254 b
23401	23401
23402	23402
23403	23403	HB3779- 652 -LRB104 11172 AAS 21254 b HB3779 - 652 - LRB104 11172 AAS 21254 b
23404	23404	HB3779 - 652 - LRB104 11172 AAS 21254 b
23405	23405	1 acquire property for public ownership and private control and
23406	23406	2 if the primary purpose of the acquisition is one of the
23407	23407	3 purposes specified in item (iii) of this subsection and the
23408	23408	4 condemning authority elects to proceed under this subsection,
23409	23409	5 then the condemning authority must prove by a preponderance of
23410	23410	6 the evidence that: (i) the acquisition of the property is
23411	23411	7 necessary for a public purpose; (ii) the acquired property
23412	23412	8 will be owned by the condemning authority or another
23413	23413	9 governmental entity; and (iii) the acquired property will be
23414	23414	10 controlled by a private party that operates a business or
23415	23415	11 facility related to the condemning authority's operation of a
23416	23416	12 university, medical district, hospital, exposition or
23417	23417	13 convention center, mass transportation facility, or airport,
23418	23418	14 including, but not limited to, a medical clinic, research and
23419	23419	15 development center, food or commercial concession facility,
23420	23420	16 social service facility, maintenance or storage facility,
23421	23421	17 cargo facility, rental car facility, bus facility, taxi
23422	23422	18 facility, flight kitchen, fixed based operation, parking
23423	23423	19 facility, refueling facility, water supply facility, and
23424	23424	20 railroad tracks and stations.
23425	23425	21 (f-5) For all acquisitions governed by subsection (c)
23426	23426	22 where the property, or any right or interest in property, is to
23427	23427	23 be used for utility purposes, and where the condemning
23428	23428	24 authority is an entity required to submit an integrated
23429	23429	25 resource plan under the Municipal and Cooperative Electric
23430	23430	26 Utility Planning and Transparency Act, the rebuttable
23431	23431
23432	23432
23433	23433
23434	23434
23435	23435
23436	23436	HB3779 - 652 - LRB104 11172 AAS 21254 b
23437	23437
23438	23438
23439	23439	HB3779- 653 -LRB104 11172 AAS 21254 b HB3779 - 653 - LRB104 11172 AAS 21254 b
23440	23440	HB3779 - 653 - LRB104 11172 AAS 21254 b
23441	23441	1 presumption described in subsection (c) shall only apply if
23442	23442	2 the most recent integrated resource plan filed by the
23443	23443	3 condemning authority identified the facility or articulated a
23444	23444	4 need for a facility of similar capacity and type to the
23445	23445	5 facility for which the property or right or interest is
23446	23446	6 sought.
23447	23447	7 (g) This Article is a limitation on the exercise of the
23448	23448	8 power of eminent domain, but is not an independent grant of
23449	23449	9 authority to exercise the power of eminent domain.
23450	23450	10 (Source: P.A. 94-1055, eff. 1-1-07.)
23451	23451	11 Section 999. Effective date. This Act takes effect upon
23452	23452	12 becoming law.
23453	23453	HB3779- 654 -LRB104 11172 AAS 21254 b 1 INDEX 2 Statutes amended in order of appearance 3 New Act4 5 ILCS 120/2from Ch. 102, par. 425 20 ILCS 605/605-10756 20 ILCS 3855/1-57 20 ILCS 3855/1-108 20 ILCS 3855/1-209 20 ILCS 3855/1-5610 20 ILCS 3855/1-7511 20 ILCS 3855/1-79 new12 20 ILCS 3855/1-93 new13 55 ILCS 5/Div. 5-46 14 heading new15 55 ILCS 5/5-46005 new16 55 ILCS 5/5-46010 new17 55 ILCS 5/5-46015 new18 55 ILCS 5/5-46020 new19 55 ILCS 5/5-46025 new20 65 ILCS 5/Art. 11 Div. 21 15.5 heading new22 65 ILCS 5/11-15.5-5 new23 65 ILCS 5/11-15.5-10 new24 65 ILCS 5/11-15.5-15 new25 65 ILCS 5/11-15.5-20 new HB3779- 655 -LRB104 11172 AAS 21254 b HB3779- 654 -LRB104 11172 AAS 21254 b HB3779 - 654 - LRB104 11172 AAS 21254 b 1 INDEX 2 Statutes amended in order of appearance 3 New Act 4 5 ILCS 120/2 from Ch. 102, par. 42 5 20 ILCS 605/605-1075 6 20 ILCS 3855/1-5 7 20 ILCS 3855/1-10 8 20 ILCS 3855/1-20 9 20 ILCS 3855/1-56 10 20 ILCS 3855/1-75 11 20 ILCS 3855/1-79 new 12 20 ILCS 3855/1-93 new 13 55 ILCS 5/Div. 5-46 14 heading new 15 55 ILCS 5/5-46005 new 16 55 ILCS 5/5-46010 new 17 55 ILCS 5/5-46015 new 18 55 ILCS 5/5-46020 new 19 55 ILCS 5/5-46025 new 20 65 ILCS 5/Art. 11 Div. 21 15.5 heading new 22 65 ILCS 5/11-15.5-5 new 23 65 ILCS 5/11-15.5-10 new 24 65 ILCS 5/11-15.5-15 new 25 65 ILCS 5/11-15.5-20 new HB3779- 655 -LRB104 11172 AAS 21254 b HB3779 - 655 - LRB104 11172 AAS 21254 b
23454	23454	HB3779- 654 -LRB104 11172 AAS 21254 b HB3779 - 654 - LRB104 11172 AAS 21254 b
23455	23455	HB3779 - 654 - LRB104 11172 AAS 21254 b
23456	23456	1 INDEX
23457	23457	2 Statutes amended in order of appearance
23458	23458	3 New Act
23459	23459	4 5 ILCS 120/2 from Ch. 102, par. 42
23460	23460	5 20 ILCS 605/605-1075
23461	23461	6 20 ILCS 3855/1-5
23462	23462	7 20 ILCS 3855/1-10
23463	23463	8 20 ILCS 3855/1-20
23464	23464	9 20 ILCS 3855/1-56
23465	23465	10 20 ILCS 3855/1-75
23466	23466	11 20 ILCS 3855/1-79 new
23467	23467	12 20 ILCS 3855/1-93 new
23468	23468	13 55 ILCS 5/Div. 5-46
23469	23469	14 heading new
23470	23470	15 55 ILCS 5/5-46005 new
23471	23471	16 55 ILCS 5/5-46010 new
23472	23472	17 55 ILCS 5/5-46015 new
23473	23473	18 55 ILCS 5/5-46020 new
23474	23474	19 55 ILCS 5/5-46025 new
23475	23475	20 65 ILCS 5/Art. 11 Div.
23476	23476	21 15.5 heading new
23477	23477	22 65 ILCS 5/11-15.5-5 new
23478	23478	23 65 ILCS 5/11-15.5-10 new
23479	23479	24 65 ILCS 5/11-15.5-15 new
23480	23480	25 65 ILCS 5/11-15.5-20 new
23481	23481	HB3779- 655 -LRB104 11172 AAS 21254 b HB3779 - 655 - LRB104 11172 AAS 21254 b
23482	23482	HB3779 - 655 - LRB104 11172 AAS 21254 b
23483	23483
23484	23484
23485	23485
23486	23486
23487	23487
23488	23488	HB3779 - 653 - LRB104 11172 AAS 21254 b
23489	23489
23490	23490
23491	23491
23492	23492	HB3779- 654 -LRB104 11172 AAS 21254 b HB3779 - 654 - LRB104 11172 AAS 21254 b
23493	23493	HB3779 - 654 - LRB104 11172 AAS 21254 b
23494	23494	1 INDEX
23495	23495	2 Statutes amended in order of appearance
23496	23496	3 New Act
23497	23497	4 5 ILCS 120/2 from Ch. 102, par. 42
23498	23498	5 20 ILCS 605/605-1075
23499	23499	6 20 ILCS 3855/1-5
23500	23500	7 20 ILCS 3855/1-10
23501	23501	8 20 ILCS 3855/1-20
23502	23502	9 20 ILCS 3855/1-56
23503	23503	10 20 ILCS 3855/1-75
23504	23504	11 20 ILCS 3855/1-79 new
23505	23505	12 20 ILCS 3855/1-93 new
23506	23506	13 55 ILCS 5/Div. 5-46
23507	23507	14 heading new
23508	23508	15 55 ILCS 5/5-46005 new
23509	23509	16 55 ILCS 5/5-46010 new
23510	23510	17 55 ILCS 5/5-46015 new
23511	23511	18 55 ILCS 5/5-46020 new
23512	23512	19 55 ILCS 5/5-46025 new
23513	23513	20 65 ILCS 5/Art. 11 Div.
23514	23514	21 15.5 heading new
23515	23515	22 65 ILCS 5/11-15.5-5 new
23516	23516	23 65 ILCS 5/11-15.5-10 new
23517	23517	24 65 ILCS 5/11-15.5-15 new
23518	23518	25 65 ILCS 5/11-15.5-20 new
23519	23519
23520	23520
23521	23521
23522	23522
23523	23523
23524	23524	HB3779 - 654 - LRB104 11172 AAS 21254 b
23525	23525
23526	23526
23527	23527	HB3779- 655 -LRB104 11172 AAS 21254 b HB3779 - 655 - LRB104 11172 AAS 21254 b
23528	23528	HB3779 - 655 - LRB104 11172 AAS 21254 b
23529	23529
23530	23530
23531	23531
23532	23532
23533	23533
23534	23534	HB3779 - 655 - LRB104 11172 AAS 21254 b