Texas Senate's ERCOT Market Reforms: New Reliability A/S Required To Be Purchased By LSEs; Allocation Of A/S To LSEs, Generators

10 GW Of PUC-Directed, Cost-Based Generation

Separate Opportunity For TDUs To Own 5 GW Of Generation

PCM Costs To Be Assigned To Generators, Cost Capped

End Of RPS; New Dispatchable Credits Program

March 9, 2023

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Copyright 2010-21 EnergyChoiceMatters.com
Reporting by Paul Ring • ring@energychoicematters.com

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Below is a summary of bills backed by the Texas Lt. Gov. and a group of both Republican and Democrat senators to address ERCOT market reform and winter storm Uri

As noted in our related story today, one of the bills would cap, corporate-wide, a REP's customer base at 20% of the market

New Reliability Services For LSEs; A/S Cost Allocation

SB7 provides that ERCOT shall, "develop an ancillary services program that requires load serving entities to purchase dispatchable reliability reserve services on a day-ahead basis to account for market uncertainty."

Such program must provide payments only to generation resources that are not providing other ancillary services.

Under this dispatchable reliability reserve service ERCOT 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 renewable intermittency and forced outage rates; and

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

(A) have a runtime of at least four hours;

(B) be available not less than two hours after being called on for deployment; and

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

SB7 also provides that ERCOT shall allocate the cost of providing ancillary services and reliability services under Section 39.159, Utilities Code on an annual basis among dispatchable generation facilities, non-dispatchable generation facilities, and load serving entities in proportion to their contribution to net load variability over the highest 100 hours of net load in the preceding year as follows (the following applies only to a generation facility or load serving entity that has participated in the ERCOT market for at least one year):

(A) for dispatchable generation facilities, the difference between the mean of the highest quartile forced outage rate for the facility and the mean forced outage rate of all dispatchable generation facilities in the ERCOT power region;

(B) for non-dispatchable generation facilities, the difference between the mean of the lowest quartile generation for each non-dispatchable generation facility, divided by the installed capacity of that facility, and the mean generation of all non-dispatchable generation facilities in the ERCOT power region, divided by the total installed capacity of all non-dispatchable generation facilities in the ERCOT power region; and

(C) for load serving entities, the difference between the mean of the highest quartile of each entity's metered load and the mean of each entity's metered load.

Cost-Based PUC-Selected New Reliability Generation

SB6 would permit the development of generation selected and directed by the PUC for back-up reliability, with cost-based rates and costs allocated to LSEs including REPs

SB6 would create the Texas Energy Insurance Program, allowing the PUC to direct the development of up to 10 GW of reliability generating assets, with compensation based on the unit's costs, and recovered from LSEs.

Authors of the bill said that the reliability assets under the insurance program would be, "last on, and first off," when called upon (dispatch noted further below)

Concerning the rates charged to customers for assets under the Texas Energy Insurance Program, SB6 provides that, "the commission [PUC] shall approve the rates and order each retail electric provider, municipally owned utility, and electric cooperative in the ERCOT power region, beginning on the commercial operation date of each reliability asset, to: (1) collect the rate from the provider's, utility's, or cooperative's retail customers in the ERCOT power region; and (2) remit the payment to the independent organization certified under Section 39.151 monthly."

Furthermore, SB6 provides that each retail electric provider, municipally owned utility, and electric cooperative in the ERCOT power region, "shall allocate the [Texas Energy Insurance Program] rates to each retail customer based on the customer's annual system demand, not peak demand."

The PUC shall prohibit a wholesale or retail customer of a transmission and distribution utility, municipally owned utility, or electric cooperative in the ERCOT power region from avoiding any stranded cost recovery charges related to the Texas Energy Insurance Program

Reliability assets under the Texas Energy Insurance Program would be dispatched by the independent organization certified under Section 39.151 for the ERCOT power region: (1) when operating reserves drop below 1,000 megawatts and the independent organization does not expect operating reserves to recover for at least 30 minutes; or (2) up to 336 hours per year for testing purposes and as directed by the independent organization.

TDU-Owned Generation

SB 2012 provides an opportunity to TDU-owned generation

SB 2012 provides that, notwithstanding any other law, if the PUC determines under Section 39.701 that less than 5,000 megawatts of dispatchable generation capacity was installed in the ERCOT power region between June 1, 2023, and December 31, 2026, the commission shall require transmission and distribution utilities to install an amount of dispatchable generation capacity sufficient to ensure that an additional 5,000 megawatts of dispatchable generation capacity is available in the ERCOT power region compared to the amount of installed dispatchable generation capacity on June 1, 2023. Costs incurred by a transmission and distribution utility under this section are recoverable in the utility's rates

The bill provides that, "A transmission and distribution utility that installs dispatchable generation capacity under this section shall register as a power generation company," indicating that the referenced installation of generation by the TDU is intended to be by the TDU itself (TDU-owned), and not from a third-party that the TDU selects for development and ownership

PCM

SB2012 limits the PUC's ability to adopt a performance credit mechanism. Notably, SB2012 would provide that, under any PCM, the cost of credits shall be assigned to generation facilities on a cost-causation basis rather than to load serving entities

SB2012 specifically provides as follows with respect to a PCM:

Sec. 39.1595. RELIABILITY PROGRAM. The commission may not adopt a reliability program for the ERCOT power region that requires the purchase of credits earned by generators based on generator availability during times of high demand and low supply at a centrally determined clearing price unless the commission ensures that:

(1) the net cost to the ERCOT market of the program does not exceed $500 million;

(2) credits are available only for dispatchable generation;

(3) the cost of credits is assigned to generation facilities on a cost-causation basis rather than to load serving entities;

(4) the program includes appropriate penalties for a failure to provide a required program service;

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

(6) the entire program is initiated on a single starting date.

Dispatchable Credits Trading Program

SB2015 would authorize the creation of a dispatchable credits trading program if certain conditions (noted below) are met Notably, per the bill's text, the program would apply to a power generation company, municipally owned utility, or electric cooperative, and not retail electric providers

Under Subsection (a), SB2015 provides that it is the intent of the legislature that 50 percent of the megawatts of generating capacity installed in the state after January 1, 2024 be dispatchable

"Any power generation company, municipally owned utility, or electric cooperative that does not satisfy the requirements of Subsection (a) by directly owning or purchasing capacity using dispatchable generation technologies shall purchase sufficient dispatchable generation energy credits to satisfy the requirements by holding dispatchable generation energy credits in lieu of capacity from dispatchable generation energy technologies," the bill provides

"On or before January 1, 2027, the commission shall activate the dispatchable generation energy credits trading program established by this section if the commission determines that dispatchable generation generating capacity installed in this state after January 1, 2024, may fall below 55 percent of all generating capacity installed in this state after January 1, 2024," the bill provides

RPS Repeal

SB2014 would repeal Sections 39.904, Utilities Code, the goal for renewable energy (RPS) and related Sections 39.916(g) (which addresses RECs from renewable distributed generation)

Other bills

Other bills included in the suite that do not have material retail market impacts include:

SB 2010

SB 2011

SB 2013

SB 1287

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