Texas 2023 - 88th Regular

Texas Senate Bill SB7 Compare Versions

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1	1	88R31129 CXP-D
2	2	By: Schwertner, et al. S.B. No. 7
3	3	(Hunter)
4	4	Substitute the following for S.B. No. 7: No.
5	5
6	6
7	7	A BILL TO BE ENTITLED
8	8	AN ACT
9	9	relating to the reliability of the ERCOT power grid.
10	10	BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF TEXAS:
11	11	SECTION 1. The heading to Section 39.159, Utilities Code,
12	12	as added by Chapter 426 (S.B. 3), Acts of the 87th Legislature,
13	13	Regular Session, 2021, is amended to read as follows:
14	14	Sec. 39.159. POWER REGION RELIABILITY AND DISPATCHABLE
15	15	GENERATION.
16	16	SECTION 2. Section 39.159, Utilities Code, as added by
17	17	Chapter 426 (S.B. 3), Acts of the 87th Legislature, Regular
18	18	Session, 2021, is amended by adding Subsections (d), (e), and (f) to
19	19	read as follows:
20	20	(d) The commission shall require the independent
21	21	organization certified under Section 39.151 for the ERCOT power
22	22	region to consider implementing an ancillary services program to
23	23	procure dispatchable reliability reserve services on a day-ahead
24	24	and real-time basis to account for market uncertainty. The program
25	25	to be considered may:
26	26	(1) determine the quantity of services necessary based
27	27	on historical variations in generation availability for each season
28	28	based on a targeted reliability standard or goal, including
29	29	intermittency of non-dispatchable generation facilities and forced
30	30	outage rates, for dispatchable generation facilities;
31	31	(2) develop criteria for resource participation that
32	32	require a resource to:
33	33	(A) be capable of running for at least four hours
34	34	at the resource's high sustained limit or for more than four hours
35	35	as the organization determines is needed;
36	36	(B) be online and dispatchable not more than two
37	37	hours after being called on for deployment; and
38	38	(C) have the dispatchable flexibility to address
39	39	inter-hour operational challenges; and
40	40	(3) reduce the amount of reliability unit commitment
41	41	by the amount of dispatchable reliability reserve services procured
42	42	under this section.
43	43	(e) The independent organization certified under Section
44	44	39.151 for the ERCOT power region may implement programs described
45	45	by Subsections (d) and (f) simultaneously.
46	46	(f) The commission shall require the independent
47	47	organization certified under Section 39.151 for the ERCOT power
48	48	region to develop and implement a program to ensure minimum
49	49	generation performance during times of high reliability risk due to
50	50	low operating reserves. The program must:
51	51	(1) apply to each electric power generation resource
52	52	in the ERCOT power region that enters into a signed generator
53	53	interconnection agreement after January 1, 2026;
54	54	(2) be independently evaluated by the wholesale
55	55	electric market monitor, including a historical analysis;
56	56	(3) allow entities, at the portfolio level, to meet
57	57	the performance requirements by supplementing or contracting with
58	58	on-site or off-site resources, including battery energy storage
59	59	resources and load resources;
60	60	(4) provide penalties for failing to comply with the
61	61	performance requirements and financial incentives for exceeding
62	62	those requirements, except that penalties may not apply to resource
63	63	unavailability due to planned maintenance outages or physical
64	64	transmission outages or during hours when the resource would not be
65	65	expected to perform based on the resource type; and
66	66	(5) exempt battery energy storage resources from the
67	67	generation performance requirements.
68	68	SECTION 3. Subchapter D, Chapter 39, Utilities Code, is
69	69	amended by adding Section 39.1591 to read as follows:
70	70	Sec. 39.1591. REPORT ON DISPATCHABLE AND NON-DISPATCHABLE
71	71	GENERATION FACILITIES. Not later than December 1 of each year, the
72	72	commission shall file a report with the legislature that:
73	73	(1) includes:
74	74	(A) the estimated annual costs incurred under
75	75	this subchapter by dispatchable and non-dispatchable generators to
76	76	guarantee that a firm amount of electric energy will be provided for
77	77	the ERCOT power grid; and
78	78	(B) as calculated by the independent system
79	79	operator, the cumulative annual costs that have been incurred in
80	80	the ERCOT market to facilitate the transmission of dispatchable and
81	81	non-dispatchable electricity to load and to interconnect
82	82	transmission level loads;
83	83	(2) documents the status of the implementation of this
84	84	subchapter, including whether the rules and protocols adopted to
85	85	implement this subchapter have materially improved the
86	86	reliability, resilience, and transparency of the electricity
87	87	market; and
88	88	(3) includes recommendations for any additional
89	89	legislative measures needed to empower the commission to implement
90	90	market reforms to ensure that market signals are adequate to
91	91	preserve existing dispatchable generation and incentivize the
92	92	construction of new dispatchable generation sufficient to maintain
93	93	reliability standards for at least five years after the date of the
94	94	report.
95	95	SECTION 4. Subchapter D, Chapter 39, Utilities Code, is
96	96	amended by adding Section 39.166 to read as follows:
97	97	Sec. 39.166. RELIABILITY PROGRAM. (a) The commission may
98	98	not require retail customers or load-serving entities in the ERCOT
99	99	power region to purchase credits designed to support a required
100	100	reserve margin or other capacity or reliability requirement until:
101	101	(1) the independent organization certified under
102	102	Section 39.151 for the ERCOT power region and the wholesale
103	103	electric market monitor complete an updated assessment on the cost
104	104	to and effects on the ERCOT market of the proposed reliability
105	105	program; and
106	106	(2) the independent organization certified under
107	107	Section 39.151 for the ERCOT power region begins implementing real
108	108	time co-optimization of energy and ancillary services in the ERCOT
109	109	wholesale market.
110	110	(b) The assessment required under Subsection (a) must
111	111	include:
112	112	(1) an evaluation of the cost of new entry and the
113	113	effects of the proposed reliability program on consumer costs and
114	114	the competitive retail market;
115	115	(2) a compilation of detailed information regarding
116	116	cost offsets realized through a reduction in costs in the energy and
117	117	ancillary services markets and use of reliability unit commitments;
118	118	(3) a set of metrics to measure the effects of the
119	119	proposed reliability program on system reliability;
120	120	(4) an evaluation of the cost to retain existing
121	121	dispatchable resources in the ERCOT power region;
122	122	(5) an evaluation of the planned timeline for
123	123	implementation of real time co-optimization for energy and
124	124	ancillary services in the ERCOT power region; and
125	125	(6) anticipated market and reliability effects of new
126	126	and updated ancillary service products.
127	127	(c) The commission may not implement a reliability program
128	128	described by Subsection (a) unless the commission by rule
129	129	establishes the essential features of the program, including
130	130	requirements to meet the reliability needs of the power region, and
131	131	the program:
132	132	(1) requires the independent organization certified
133	133	under Section 39.151 for the ERCOT power region to procure the
134	134	credits centrally in a manner designed to prevent market
135	135	manipulation by affiliated generation and retail companies;
136	136	(2) limits participation in the program to
137	137	dispatchable resources with the specific attributes necessary to
138	138	meet operational needs of the ERCOT power region;
139	139	(3) ensures that a generator cannot receive credits
140	140	that exceed the amount of generation bid into the forward market by
141	141	that generator;
142	142	(4) ensures that an electric generating unit can
143	143	receive a credit only for being available to perform in real time
144	144	during the tightest intervals of low supply and high demand on the
145	145	grid, as defined by the commission on a seasonal basis;
146	146	(5) establishes a penalty structure, resulting in a
147	147	net benefit to load, for generators that bid into the forward market
148	148	but do not meet the full obligation;
149	149	(6) provides the wholesale electric market monitor
150	150	with the authority and resources necessary to investigate potential
151	151	instances of market manipulation by any means, including by
152	152	financial or physical actions;
153	153	(7) ensures that any program reliability standard
154	154	reasonably balances the incremental reliability benefits to
155	155	customers against the incremental costs of the program based on an
156	156	evaluation by the wholesale electric market monitor;
157	157	(8) establishes a single ERCOT-wide clearing price for
158	158	the program and does not differentiate payments or credit values
159	159	based on locational constraints;
160	160	(9) does not assign costs, credit, or collateral for
161	161	the program in a manner that provides a cost advantage to
162	162	load-serving entities who own, or whose affiliates own, generation
163	163	facilities;
164	164	(10) requires sufficient secured collateral so that
165	165	other market participants do not bear the risk of non-performance
166	166	or non-payment;
167	167	(11) ensures that the cost of all credits paid to
168	168	dispatchable resources is allocated to loads based on an hourly
169	169	load ratio share; and
170	170	(12) removes any market changes implemented as a
171	171	bridge solution for the program not later than the first
172	172	anniversary of the date the program was implemented.
173	173	(d) The commission and the independent organization
174	174	certified under Section 39.151 for the ERCOT power region may not
175	175	adopt a market rule for the ERCOT power region associated with the
176	176	implementation of a reliability program described by Subsection (a)
177	177	that provides a cost advantage to load-serving entities who own, or
178	178	whose affiliates own, generation facilities.
179	179	(e) The commission and the independent organization
180	180	certified under Section 39.151 for the ERCOT power region shall
181	181	ensure that the net cost imposed on the ERCOT market for the credits
182	182	does not exceed $1 billion annually, less the cost of any interim or
183	183	bridge solutions that are lawfully implemented, except that the
184	184	commission may adjust the limit:
185	185	(1) proportionally according to the highest net peak
186	186	demand year-over-year with a base year of 2026; and
187	187	(2) for inflation with a base year of 2026.
188	188	(f) The wholesale electric market monitor biennially shall:
189	189	(1) evaluate the incremental reliability benefits of
190	190	the program for consumers compared to the costs to consumers of the
191	191	program and the costs in the energy and ancillary services markets;
192	192	and
193	193	(2) report the results of each evaluation to the
194	194	legislature.
195	195	SECTION 5. (a) Not later than September 1, 2024, the
196	196	Public Utility Commission of Texas shall implement the changes in
197	197	law made by Section 39.159(f), Utilities Code, as added by this Act.
198	198	(b) The Public Utility Commission of Texas shall require the
199	199	independent organization certified under Section 39.151, Utilities
200	200	Code, for the ERCOT power region to implement the program required
201	201	by Section 39.159(d), Utilities Code, as added by this Act, not
202	202	later than December 1, 2024.
203	203	(c) The Public Utility Commission of Texas is required to
204	204	prepare the portions of the report required by Sections 39.1591(2)
205	205	and (3), Utilities Code, as added by this Act, only for reports due
206	206	on or after December 1, 2024.
207	207	(d) Not later than December 31, 2024, the wholesale electric
208	208	market monitor described by Section 39.1515, Utilities Code, shall
209	209	submit to the legislature recommendations regarding the
210	210	implementation of the program required by Section 39.159(f),
211	211	Utilities Code, as added by this Act.
212	212	SECTION 6. This Act takes effect immediately if it receives
213	213	a vote of two-thirds of all the members elected to each house, as
214	214	provided by Section 39, Article III, Texas Constitution. If this
215	215	Act does not receive the vote necessary for immediate effect, this
216	216	Act takes effect September 1, 2023.