Texas 2025 - 89th Regular

Texas Senate Bill SB6 Compare Versions

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Version 2 (New)

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1	1		By: King, et al. S.B. No. 6
	2	+	(In the Senate - Filed February 12, 2025; February 13, 2025,
	3	+	read first time and referred to Committee on Business & Commerce;
	4	+	March 13, 2025, reported adversely, with favorable Committee
	5	+	Substitute by the following vote: Yeas 10, Nays 0; March 13, 2025,
	6	+	sent to printer.)
	7	+	Click here to see the committee vote
	8	+	COMMITTEE SUBSTITUTE FOR S.B. No. 6 By: King
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6	13		A BILL TO BE ENTITLED
7	14		AN ACT
8	15		relating to electricity planning and infrastructure costs for large
9	16		loads.
10	17		BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF TEXAS:
11	18		SECTION 1. Section 35.004, Utilities Code, is amended by
12	19		adding Subsections (c-1) and (c-2) to read as follows:
13	20		(c-1) The commission by rule shall ensure that a large load
14	21		customer who is subject to the standards adopted under Section
15	22		37.0561 contributes to the recovery of the interconnecting electric
16		-	utility's costs to interconnect the large load to the ~~utility's~~
	23	+	utility's costs to interconnect the large load to the transmission
17	24		system.
18	25		(c-2) An electric cooperative or municipally owned utility
19	26		that has not adopted customer choice shall pass through to a large
20	27		load customer who is subject to the standards adopted under Section
21		-	37.0561 the reasonable costs to interconnect the large load ~~in a~~
22		-	manner determined by the electric ~~cooperative or municipally owned~~
23		-	utility.
	28	+	37.0561 the reasonable costs to interconnect the large load to the
	29	+	transmission system in a manner determined by the electric
	30	+	cooperative or municipally owned utility.
24	31		SECTION 2. Subchapter B, Chapter 37, Utilities Code, is
25	32		amended by adding Section 37.0561 to read as follows:
26	33		Sec. 37.0561. PLANNING REQUIREMENTS FOR LARGE LOADS. (a)
27	34		The commission by rule shall establish standards for
28	35		interconnecting large load customers in the ERCOT power region in a
29	36		manner designed to support business development in this state while
30		-	minimizing the potential for stranded infrastructure costs and
31		-	maintaining system reliability.
	37	+	minimizing the potential for stranded infrastructure costs.
32	38		(b) The standards must apply only to customers requesting a
33	39		new or expanded interconnection where the total load at a single
34	40		site would exceed a demand threshold established by the commission
35	41		based on the size of loads that significantly impact transmission
36	42		needs in the ERCOT power region. The commission shall establish a
37	43		demand threshold of 75 megawatts unless the commission determines
38	44		that a lower threshold is necessary to accomplish the purposes
39	45		described by Subsection (a).
40	46		(c) The standards must require each large load customer
41	47		subject to Subsection (b) to disclose to the interconnecting
42	48		electric utility or municipally owned utility whether the customer
43	49		is pursuing a substantially similar request for electric service,
44	50		inside or outside this state, the approval of which would result in
45	51		the customer materially changing, delaying, or withdrawing the
46		-	interconnection request. The disclosure may ~~withhold or anonymize~~
47		-	~~competitively sensitive~~ details. The commission by rule shall
48		-	~~prohibit an~~ electric utility or municipally owned utility from
49		-	~~selling,~~ sharing, or disclosing information submitted to the
50		-	~~utility under~~ this subsection other than a disclosure to the
51		-	~~commission or the~~ independent organization certified under Section
52		-	~~39.151 for the~~ ERCOT power region, subject to appropriate
53		-	~~confidentiality~~ protections.
	52	+	interconnection request. The disclosure may not require project
	53	+	specific details. The commission by rule shall prohibit an
	54	+	electric utility or municipally owned utility from selling,
	55	+	sharing, or disclosing information submitted to the utility under
	56	+	this subsection other than a disclosure to the commission or the
	57	+	independent organization certified under Section 39.151 for the
	58	+	ERCOT power region, subject to appropriate confidentiality
	59	+	protections.
54	60		(d) The standards must require each interconnected large
55	61		load customer subject to Subsection (b) to disclose to the
56	62		interconnecting electric utility or municipally owned utility
57	63		information about the customer's on-site backup generating
58	64		facilities and require the interconnecting electric utility or
59	65		municipally owned utility to provide the information to the
60	66		independent organization certified under Section 39.151 for the
61	67		ERCOT power region. For the purposes of this subsection, "on-site
62	68		backup generating facilities" means generation that is not capable
63	69		of exporting energy to the ERCOT transmission grid and that, in the
64	70		aggregate, can serve at least 50 percent of on-site demand. The
65	71		independent organization certified under Section 39.151 for the
66	72		ERCOT power region shall establish a threshold during an energy
67	73		emergency alert where the organization may, after reasonable
68	74		notice, direct the applicable electric utility or municipally owned
69	75		utility to require the large load customer to either deploy the
70	76		customer's on-site backup generating facility or curtail load. The
71	77		independent organization certified under Section 39.151 for the
72	78		ERCOT power region shall include a deployment under this section as
73	79		firm load shed when calculating any price adjustments for
74	80		reliability deployments. This subsection does not:
75	81		(1) authorize or require a violation of any emissions
76	82		limitation in state or federal law or a violation of any other
77	83		environmental regulation; or
78	84		(2) prohibit a large load customer from participating
79	85		in a service authorized by Section 39.170(b).
80	86		(e) The standards must set a flat study fee of at least
81	87		$100,000 to be paid to the interconnecting electric utility or
82	88		municipally owned utility for initial transmission screening
83	89		studies for large loads subject to Subsection (b). A large load
84	90		customer that requests additional capacity following the screening
85	91		study must pay an additional study fee based on the new request.
86	92		The interconnecting electric utility or municipally owned utility
87	93		shall apply any unused portion of the initial transmission
88	94		screening study fee as a credit toward satisfying financial
89	95		obligations for procurement or interconnection agreements at the
90	96		same geographic site.
91	97		(f) The standards must include a method for a large load
92		-	customer subject to Subsection (b) to demonstrate site control ~~for~~
93		-	the ~~proposed~~ load ~~location~~ through an ownership interest, ~~lease, or~~
94		-	another legal interest acceptable to the commission.
	98	+	customer subject to Subsection (b) to demonstrate site control
	99	+	where the load will be located through an ownership interest,
	100	+	lease, or another legal interest acceptable to the commission.
95	101		(g) The standards must include uniform financial commitment
96	102		standards for the development of transmission infrastructure
97	103		needed to serve a large load customer subject to Subsection (b)
98	104		before an electric utility or municipally owned utility may submit
99	105		a project for review to the independent organization certified
100	106		under Section 39.151 for the ERCOT power region based on the large
101	107		load customer's demand. The standards must provide that
102	108		satisfactory proof of financial commitment may include:
103	109		(1) security provided on a dollar per megawatt basis
104	110		as set by the commission;
105	111		(2) contribution in aid of construction;
106	112		(3) security provided under an agreement that requires
107	113		a large load customer to pay for significant equipment or services
108	114		in advance of signing an agreement to establish electric delivery
109	115		service; or
110	116		(4) a form of financial commitment acceptable to the
111	117		commission other than those provided by Subdivisions (1)-(3).
112	118		(h) Security provided under Subsection (g)(1) must be
113		-	refunded, in whole or in part, after the security is applied to any
114		-	outstanding amounts owed:
115		-	(1) as the large load customer meets the customer's
116		-	load ramp milestones and sustains operations for a prescribed
117		-	period as determined by the commission; or
118		-	(2) if the large load customer withdraws the
119		-	customer's request for all or a portion of the requested capacity.
120		-	(i) The standards must establish a procedure to allow the
121		-	independent organization certified under Section 39.151 for the
122		-	ERCOT power region to access any information collected by the
123		-	interconnecting electric utility or municipally owned utility to
124		-	ensure compliance with the standards for transmission planning
125		-	analysis. Any customer-specific or competitively sensitive
126		-	information obtained under this subsection is confidential and not
127		-	subject to disclosure under Chapter 552, Government Code.
	119	+	refunded, in whole or in part, as the large load customer meets the
	120	+	customer's load ramp milestones and sustains operations for a
	121	+	prescribed period as determined by the commission.
	122	+	(i) The standards must allow the independent organization
	123	+	certified under Section 39.151 for the ERCOT power region to access
	124	+	any information collected from the interconnecting electric
	125	+	utility or municipally owned utility, using procedures established
	126	+	by the commission, to ensure compliance with the standards for
	127	+	transmission planning analysis. Any customer-specific or
	128	+	competitively sensitive information obtained under this subsection
	129	+	is confidential and not subject to disclosure under Chapter 552,
	130	+	Government Code.
128	131		(j) The commission may not limit the authority of a
129	132		municipally owned utility or an electric cooperative to impose
130	133		retail electric service requirements for large load customers on
131	134		their systems in addition to the standards adopted under this
132	135		section.
133		-	(k) Notwithstanding the forecasted load growth and
134		-	additional load currently seeking interconnection required to be
135		-	considered under Section 37.056(c-1), the commission by rule shall
136		-	establish criteria by which the independent organization certified
137		-	under Section 39.151 for the ERCOT power region includes forecasted
138		-	large load of any peak demand in the organization's transmission
139		-	planning and resource adequacy models and reports.
140	136		SECTION 3. Section 39.002, Utilities Code, is amended to
141	137		read as follows:
142	138		Sec. 39.002. APPLICABILITY. This chapter, other than
143	139		Sections 39.151, 39.1516, 39.155, 39.157(e), 39.161, 39.162,
144	140		39.163, 39.169, 39.170, 39.203, 39.9051, 39.9052, and 39.914(e),
145	141		and Subchapters M and N, does not apply to a municipally owned
146	142		utility or an electric cooperative. Sections 39.157(e) and 39.203
147	143		apply only to a municipally owned utility or an electric
148	144		cooperative that is offering customer choice. If there is a
149	145		conflict between the specific provisions of this chapter and any
150	146		other provisions of this title, except for Chapters 40 and 41, the
151	147		provisions of this chapter control.
152	148		SECTION 4. Subchapter D, Chapter 39, Utilities Code, is
153	149		amended by adding Sections 39.169 and 39.170 to read as follows:
154	150		Sec. 39.169. CO-LOCATION OF RETAIL CUSTOMER WITH EXISTING
155	151		GENERATION RESOURCE. (a) A power generation company, municipally
156	152		owned utility, or electric cooperative must submit a notice to the
157	153		commission and the independent organization certified under
158	154		Section 39.151 for the ERCOT power region before implementing a net
159	155		metering arrangement between an existing, operating facility
160	156		registered with the independent organization as a generation
161	157		resource and a new large load customer as described by Section
162	158		37.0561(b).
163	159		(b) The new net metering arrangement must be requested or
164	160		consented to by the electric cooperative, electric utility, or
165	161		municipally owned utility certificated to provide retail electric
166	162		service at the location. The electric cooperative, electric
167	163		utility, or municipally owned utility may withhold consent to a
168	164		proposal that is consistent with the determination provided under
169	165		Subsection (c) and applicable law only for a reasonable cause.
170	166		(c) With input from the independent organization certified
171	167		under Section 39.151 for the ERCOT power region, not later than the
172	168		180th day after the date the commission receives the notice under
173	169		Subsection (a), the commission shall approve, deny, or impose
174	170		reasonable conditions on a proposed net metering arrangement
175	171		described by Subsection (a) as necessary to maintain system
176	172		reliability, including transmission security and resource adequacy
177	173		impacts. The conditions may:
178	174		(1) require the retail customer who is served
179	175		behind-the-meter to reduce load during certain events;
180	176		(2) require the generation resource to make capacity
181	177		available to the ERCOT power region during certain events; or
182	178		(3) provide that the owner of the generation resource
183	179		may be held liable for stranded or underutilized transmission
184	180		assets resulting from the behind-the-meter operation.
185	181		(d) If the commission does not approve, deny, or impose
186	182		reasonable conditions on a proposed net metering arrangement before
187	183		the expiration of the deadline established by Subsection (c), the
188	184		commission is considered to have approved the arrangement.
189	185		(e) If conditions imposed under Subsection (c) are not
190	186		limited to a specific period, the commission shall review the
191	187		conditions at least every five years to determine whether the
192	188		conditions should be extended or rescinded.
193	189		(f) The parties to a proceeding under this section are
194	190		limited to the commission, the independent organization certified
195	191		under Section 39.151 for the ERCOT power region, the
196		-	interconnecting electric cooperative, electric utility, or
197		-	municipally owned utility, and a party in the net metering
198		-	arrangement.
	192	+	interconnecting electric utility or municipally owned utility, and
	193	+	a party in the net metering arrangement.
199	194		Sec. 39.170. LARGE LOAD DEMAND MANAGEMENT SERVICE.
200	195		(a) The commission shall require the independent organization
201	196		certified under Section 39.151 for the ERCOT power region to ensure
202	197		that each electric cooperative, electric utility, and municipally
203	198		owned utility serving a transmission-voltage customer develops a
204	199		protocol and installs, or requires to be installed, before the
205	200		customer is interconnected, any necessary equipment to allow the
206	201		load to be curtailed during firm load shed. The electric
207	202		cooperative, electric utility, or municipally owned utility shall
208	203		confer with the customer to the extent feasible to shed load in a
209	204		coordinated manner. This subsection applies only to a load
210	205		interconnected after December 31, 2025, that is not:
211	206		(1) load operated by a critical load industrial
212	207		customer, as defined by Section 17.002; or
213	208		(2) designated as a critical natural gas facility
214	209		under Section 38.074.
215	210		(b) The commission shall require the independent
216	211		organization certified under Section 39.151 for the ERCOT power
217	212		region to develop a reliability service to competitively procure
218	213		demand reductions from large load customers with a demand of at
219		-	least 75 megawatts to be deployed in the event of an anticipated
220		-	emergency condition. The rules governing this service must:
	214	+	least 75 megawatts to be deployed in advance of an anticipated
	215	+	energy emergency alert event. The rules governing this service
	216	+	must:
221	217		(1) specify the periods when the service may be used to
222	218		assist with maintaining reliability during extreme weather events;
223	219		(2) ensure that the independent organization provides
224	220		at least a 24-hour notice to large load customers and requires each
225	221		large load to remain curtailed for the duration of the energy
226	222		emergency alert event or until the load can be recalled safely; and
227	223		(3) prohibit participation by any large load customer
228	224		that curtails in response to the wholesale price of electricity, as
229	225		determined by the independent organization certified under Section
230	226		39.151 for the ERCOT power region, or that otherwise participates
231	227		in a different reliability or ancillary service.
232	228		(c) The independent organization certified under Section
233	229		39.151 for the ERCOT power region shall include a deployment under
234	230		this section when calculating any price adjustments for reliability
235	231		deployments.
236	232		SECTION 5. (a) The Public Utility Commission of Texas shall
237	233		evaluate whether the existing methodology used to charge wholesale
238	234		transmission costs to distribution providers under Section
239	235		35.004(d), Utilities Code, continues to appropriately assign costs
240	236		for transmission investment. The commission shall also evaluate:
241	237		(1) whether the current four coincident peak
242	238		methodology used to calculate wholesale transmission rates ensures
243	239		that all loads appropriately contribute to the recovery of an
244	240		electric cooperative's, electric utility's, or municipally owned
245	241		utility's costs to provide access to the transmission system;
246	242		(2) whether alternative methods to calculate
247	243		wholesale transmission rates would more appropriately assign the
248	244		cost of providing access to and wholesale service from the
249	245		transmission system, such as consideration of multiple seasonal
250	246		peak demands, demand during different length daily intervals, or
251	247		peak energy intervals; and
252	248		(3) the portion of the costs related to access to and
253	249		wholesale service from the transmission system that should be
254	250		nonbypassable, consistent with Section 35.004(c-1), Utilities
255	251		Code, as added by this Act.
256	252		(b) The Public Utility Commission of Texas shall evaluate
257	253		whether the commission's retail ratemaking practices ensure that
258	254		transmission cost recovery appropriately charges the system costs
259	255		that are caused by each customer class.
260	256		(c) The Public Utility Commission of Texas shall begin the
261	257		evaluation required under Subsection (a) of this section not later
262	258		than the 90th day after the effective date of this Act. After
263	259		completion of the evaluation project and not later than December
264	260		31, 2026, the commission shall amend commission rules to ensure
265	261		that wholesale transmission charges appropriately assign costs for
266	262		transmission investment.
267	263		SECTION 6. Section 35.004(c-1), Utilities Code, as added by
268		-	this Act, applies only to an interconnection ~~agreement entered into~~
269		-	~~on or after the~~ effective date of this Act.
	264	+	this Act, applies only to an interconnection made on or after the
	265	+	effective date of this Act.
270	266		SECTION 7. This Act takes effect immediately if it receives
271	267		a vote of two-thirds of all the members elected to each house, as
272	268		provided by Section 39, Article III, Texas Constitution. If this
273	269		Act does not receive the vote necessary for immediate effect, this
274	270		Act takes effect September 1, 2025.
	271	+	* * * * *