Texas PUC Sunset Bill Heads To Governor, Includes Retail-Focused PCM Guardrails, New Uncertainty A/S Product

REP Retail Sales Report Retained; REP Demand Response Provisions Dropped

RPS Changed To Solar-Only Program For Two Years, Then Terminates

Requires Study On Pay-as-Bid Pricing For ERCOT Market

May 30, 2023

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Copyright 2010-23 EnergyChoiceMatters.com
Reporting by Paul Ring • ring@energychoicematters.com

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Both Texas Houses have agreed on and passed a version of HB1500, the PUC sunset bill, with various provisions addressing a range of electricity policy issues.

The conference version of the bill has been signed in both houses (enrolled) and should be sent to the governor shortly

Enrolled HB 1500 retains the retail sales reporting requirement for REPs, as follows:

Sec. 39.168. RETAIL SALES REPORT.

(a) Each retail electric provider that offers electricity for sale shall report to the commission:

(1) its annual retail sales in this state;

(2) the annual retail sales of its affiliates by number of customers, kilowatts per hour sold, and revenue from kilowatts per hour sold by customer class; and

(3) any other information the commission requires relating to affiliations between retail electric providers.

(b) The commission by rule shall prescribe the nature and detail of the reporting requirements. The commission may accept information reported under other law to satisfy the requirements of this section. Information reported under this section is confidential and not subject to disclosure if the information is competitively sensitive information. The commission shall administer the reporting requirements in a manner that ensures the confidentiality of competitively sensitive information.

Enrolled HB 1500 adopts a new uncertainty ancillary service product, to be implemented not later than December 1, 2024, as follows:

(d) The commission shall require the independent organization certified under Section 39.151 for the ERCOT power region to develop and implement an ancillary services program to procure dispatchable reliability reserve services on a day-ahead and real-time basis to account for market uncertainty. Under the required program, the independent organization shall:

(1) determine the quantity of services necessary based on historical variations in generation availability for each season based on a targeted reliability standard or goal, including intermittency of non-dispatchable generation facilities and forced outage rates, for dispatchable generation facilities;

(2) develop criteria for resource participation that require a resource to:

(A) be capable of running for at least four hours at the resource's high sustained limit;

(B) be online and dispatchable not more than two hours after being called on for deployment; and

(C) have the dispatchable flexibility to address inter-hour operational challenges; and

(3) reduce the amount of reliability unit commitment by the amount of dispatchable reliability reserve services procured under this section.

(e) Notwithstanding Subsection (d)(2)(A), the independent organization certified under Section 39.151 for the ERCOT power region may require a resource to be capable of running for more than four hours as the organization determines is needed.

Enrolled HB 1500 also adopts various guardrails for the performance credit mechanism (or any similar program), including a $1 billion net cost cap described further below

Notable is that, if PCM is implemented, ERCOT would be required to procure the credits centrally, "in a manner designed to prevent market manipulation by affiliated generation and retail companies[.]"

Enrolled HB 1500 would also provide that, "the terms of the program and any associated market rules do not assign costs, credit, or collateral for the program in a manner that provides a cost advantage to load-serving entities who own, or whose affiliates own, generation facilities[.]"

Enrolled HB 1500 would also require a single, ERCOT-wide clearing price under PCM, with no locational pricing

The full PCM provisions are:

Sec. 39.1594. RELIABILITY PROGRAM.

(a) Under Section 39.159(b), as added by Chapter 426 (S.B. 3), Acts of the 87th Legislature, Regular Session, 2021, or other law, the commission may not require retail customers or load-serving entities in the ERCOT power region to purchase credits designed to support a required reserve margin or other capacity or reliability requirement unless the commission ensures that:

(1) the net cost to the ERCOT market of the credits does not exceed $1 billion annually, less the cost of any interim or bridge solutions that are lawfully implemented, except that the commission may adjust the limit:

(A) proportionally according to the highest net peak demand year-over-year with a base year of 2026; and

(B) for inflation with a base year of 2026;

(2) credits are available only for dispatchable generation;

(3) the independent organization certified under Section 39.151 for the ERCOT power region is required to procure the credits centrally in a manner designed to prevent market manipulation by affiliated generation and retail companies;

(4) a generator cannot receive credits that exceed the amount of generation bid into the forward market by that generator;

(5) an electric generating unit can receive a credit only for being available to perform in real time during the tightest intervals of low supply and high demand on the grid, as defined by the commission on a seasonal basis;

(6) a penalty structure is established, resulting in a net benefit to load, for generators that bid into the forward market but do not meet the full obligation;

(7) any program reliability standard reasonably balances the incremental reliability benefits to customers against the incremental costs of the program based on an evaluation by the wholesale electric market monitor;

(8) a single ERCOT-wide clearing price is established for the program and does not differentiate payments or credit values based on locational constraints;

(9) any market changes implemented as a bridge solution for the program are removed not later than the first anniversary of the date the program was implemented;

(10) the independent organization certified under Section 39.151 for the ERCOT power region begins implementing real time co-optimization of energy and ancillary services in the ERCOT wholesale market before the program is implemented;

(11) all elements of the program are initially implemented on a single starting date;

(12) the terms of the program and any associated market rules do not assign costs, credit, or collateral for the program in a manner that provides a cost advantage to load-serving entities who own, or whose affiliates own, generation facilities;

(13) secured financial credit and collateral requirements are adopted for the program to ensure that other market participants do not bear the risk of nonperformance or nonpayment; and

(14) the wholesale electric market monitor has the authority and necessary resources to investigate potential instances of market manipulation by program participants, including financial and physical actions, and recommend penalties to the commission.

(b) This section does not require the commission to adopt a reliability program that requires an entity to purchase capacity credits.

(c) The commission and the independent organization certified under Section 39.151 for the ERCOT power region shall consider comments and recommendations from a technical advisory committee established under the bylaws of the independent organization that includes market participants when adopting and implementing a program described by Subsection (a), if any.

(d) Before the commission adopts a program described by Subsection (a), the commission shall require the independent organization certified under Section 39.151 for the ERCOT power region and the wholesale electric market monitor to complete an updated assessment on the cost to and effects on the ERCOT market of the proposed reliability program and submit to the commission and the legislature a report on the costs and benefits of continuing the program. The assessment must include:

(1) an evaluation of the cost of new entry and the effects of the proposed reliability program on consumer costs and the competitive retail market;

(2) a compilation of detailed information regarding cost offsets realized through a reduction in costs in the energy and ancillary services markets and use of reliability unit commitments;

(3) a set of metrics to measure the effects of the proposed reliability program on system reliability;

(4) an evaluation of the cost to retain existing dispatchable resources in the ERCOT power region;

(5) an evaluation of the planned timeline for implementation of real time co-optimization for energy and ancillary services in the ERCOT power region; and

(6) anticipated market and reliability effects of new and updated ancillary service products.

(e) If the commission adopts a program described by Subsection (a), the commission by rule shall prohibit a generator that receives credits through the program for a dispatchable electric generating unit operated by the generator from decommissioning or removing from service that unit while the generator participates in the program unless the decommissioning or removal from service begins after September 1, 2028, or the commission finds that the decommissioning or removal from service:

(1) is required by or is a result of federal law; or

(2) would alleviate significant financial hardship for the generator.

(f) If the commission adopts a program described by Subsection (a), the wholesale electric market monitor described by Section 39.1515 biennially shall:

(1) evaluate the incremental reliability benefits of the program for consumers compared to the costs to consumers of the program and the costs in the energy and ancillary services markets; and

(2) report the results of each evaluation to the legislature.

Enrolled HB 1500 does not include SB114's provisions concerning REP demand response programs, including a goal for demand reductions, and allowing REPs to access energy efficiency funding for demand response. See the full provisions of SB114, omitted from enrolled HB 1500, in our prior story here

Enrolled HB1500 requires a study on the allocation of ancillary service costs, as follows

Sec. 39.1593. COST ALLOCATION OF RELIABILITY SERVICES.

(a) The commission shall direct the independent organization certified under Section 39.151 for the ERCOT power region to evaluate with input from a technical advisory committee established under the bylaws of the independent organization that includes market participants whether allocating the costs of ancillary and reliability services, including those procured under Section 39.159, as added by Chapter 426 (S.B. 3), Acts of the 87th Legislature, Regular Session, 2021, using a methodology described by Subsection (b) would result in a net savings to consumers in the ERCOT power region compared to allocating all costs of ancillary and reliability services to load to ensure reliability.

(b) The commission shall evaluate whether to allocate the cost of ancillary and reliability services:

(1) on a semiannual basis among electric generation facilities and load-serving entities in proportion to their contribution to unreliability during the times of highest reliability risk due to low operating reserves by season, as determined by the commission based on a number of hours adopted by the commission for that season; or

(2) using another method identified by the commission.

(c) The evaluation must:

(1) use historical ancillary and reliability services data;

(2) consider the causes for ancillary services deployments; and

(3) consider the design, procurement, and cost allocation of ancillary services required by Section 35.004(h).

(d) Not later than December 1, 2026, the commission shall submit a report on the evaluation to the legislature.

Enrolled HB 1500 also requires the PUC to study whether a "single" (on a locational basis where applicable) clearing price for energy and ancillary services should be retained, or whether pay-as-bid should be required for certain resources

Enrolled HB1500 provides:

(d) The Public Utility Commission of Texas and the independent organization certified under Section 39.151, Utilities Code, for the ERCOT power region shall:

(1) conduct a study on whether implementing an alternative to the single market clearing price for energy, ancillary services, and other products would reduce costs to residential and small commercial customers or their load-serving entities, such as paying generators the price bid and not the additional amounts up to the highest cost generator needed to clear the market;

(2) analyze:

(A) whether cost savings can be achieved for consumers, or load-serving entities serving residential and small commercial consumers, by:

(i) limiting generators that have received state or federal subsidies to receiving the price bid by that type of generator; or

(ii) limiting a generator to receiving the price bid by that generator; and

(B) if a pay as bid mechanism is used or a single market clearing price mechanism is retained, whether non-dispatchable and dispatchable generation facilities should bid into separate markets for ERCOT power region products such that the generation facilities are directly competing against technologies with similar attributes; and

(3) report the results of the study and analysis conducted under this subsection to the legislature not later than December 1, 2025.

Enrolled HB 1500 repeals the RPS under Section 39.904, Utilities Code (goal for renewable energy) applicable to REPs, except it retains for a short period a solar RPS as follows:

SECTION 53. (a) Except as provided by Subsection (b) of this section, notwithstanding the repeal by this Act of Section 39.904, Utilities Code, the Public Utility Commission of Texas by rule shall adopt a program to apply that section as it existed immediately before the effective date of this Act, and to apply other statutes that referred to that section immediately before the effective date of this Act, as if that section had not been repealed by this Act and the other statutes that referred to that section had not been repealed or amended by this Act.

(b) Under Subsection (a) of this section, the statutes described in that subsection must be applied as if Section 39.904 were applicable only to renewable energy technologies that exclusively rely on an energy source that is naturally regenerated over a short time and derived directly from the sun.

(c) This section expires September 1, 2025, and the Public Utility Commission of Texas shall phase out the program required by Subsection (a) of this section so that it terminates on that date

Enrolled HB 1500 also requires continuation of a REC tracking system for voluntary RECs

Enrolled HB1500 includes more specific directives regarding the scope of competition report, including a requirement that such report shall include an assessment of:

(i) the effect of competition and industry restructuring on customers in both competitive and noncompetitive electric markets; and

(ii) the effect of competition on the rates and availability of electric services for residential and small commercial customers;

Enrolled HB 1500 also includes language further confirming, and expanding the use cases for, the use of mobile generation by TDUs and TDU affiliates, and eliminating a specific end date for such authorization

Also enrolled and sent to the governor is SB2627, which would provide loans for dispatchable generation but which would also allow the use of monies under the Texas energy fund to support installation of distributed back-up power generation under various circumstances

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