The Public Utility Commission of Texas (“Commission”) is engaged in the most dramatic reform of the Texas wholesale electricity market in a generation. For the first time since the market was unbundled, and an “energy-only” wholesale market introduced, the Commission has recommended a plan to develop a capacity-like payment system. The Commission’s proposed Performance Credits Mechanism (“PCM”) would require load serving entities, like retail electric providers, to purchase credits allocated to electric generators based on their actual activity during the hours of highest risk. The Commission believes that the credits will help support the operations of existing dispatchable generation, while incenting the development of new generation the Commission argues would help prevent another significant blackout. But the proposed PCM has garnered significant controversy. Stakeholders have lined up for and against the PCM proposal. And the Texas Legislature has warned the Commission against finally adopting the PCM without its approval. Both the PCM’s costs and its efficacy are in question. The ultimate resolution of this issue will shape the Texas wholesale electricity market, and indeed the Texas economy, for the next decade.
Development of Market Design Alternatives
In the aftermath of February 2021’s Winter Storm Uri, the Texas Legislature passed Senate Bill 3, which among other things required the Public Utility Commission of Texas (“Commission”) to “evaluate whether additional services are needed for reliability in the ERCOT power region while providing adequate incentives for dispatchable generation.” Tex. Util. Code 35.0021(g)(2). To that end, the Commission resolved to develop a load-side reliability mechanism and a backstop reliability service and promulgated a Market Design Blueprint calling for a study of long-term market design principles.
On November 10, 2022, the Commission’s retained consultant, Energy and Environmental Economics, Inc. (“E3”), released its “Assessment of Market Reform Options to Enhance Reliability of the ERCOT System,” The report developed and analyzed six market design options:
- Load Serving Entity Reliability Obligation (LSERO)
- Forward Reliability Market (FRM)
- Performance Credits Mechanism (PCM)
- Backstop Reliability Service (BRS)
- Dispatchable Energy Credits (DEC)
- Dispatchable Energy Credits with Backstop Reliability Service (DEC+BRS Hybrid)
E3 ultimately recommended the adoption of the FRM market design. E3 found that while the LSERO, FRM, PCM, and BRS designs each yielded similar reliability improvement at similar costs, the FRM market design was preferable on qualitative grounds. In E3’s view, reforms that require procurement of a forward reliability product provide a more natural year-to-year stability in market outcomes, and the FRM market’s centrally-cleared auction does this most effectively by providing for market power mitigation and easy integration into Texas’ dynamic retail market. In contrast, E3 noted that implementation of the PCM market design entailed significant risk because of its novelty—it has never been implemented in any jurisdiction.
Nevertheless, Commission staff filed a memorandum along with the E3 report stating that based on its review, the PCM design fulfills the requirements of Senate Bill 3 to meet reliability goals while also providing a load-side reliability mechanism. Among other things, staff noted that awarding performance credits strictly to generation resources that perform during the hours of highest reliability risk ensures that the most reliable resources receive financial compensation, requiring load serving entities to procure performance credits up to the reliability standard encourages new dispatchable generation to be built, and assessing resources based on actual performance ensures consistent generation availability during critical hours.
Commission staff also requested comments on the proposed market designs. Market stakeholders submitted thousands of pages of comments. Some supported the implementation of the PCM, others supported alternative market designs, while some argued that the market as presently constituted should continue.
After the release of the E3 report, the Texas Senate Business and Commerce Committee, which oversees the Commission, sent a unanimously signed letter expressing concerns with several of the market design proposals being considered by the PUC, particularly the PCM, and requesting the PUC delay actions towards implementing a redesign of the ERCOT market until after further deliberation by and consultation with the Texas Legislature during the 88th Legislative Session, which began in January 2023.
On January 19, 2023, the Commission, after much debate, voted to move forward with the PCM market design. It removed the DEC, FRM and LSERO proposals from any further consideration. It agreed to open a project to evaluate and establish an appropriate reliability standard, which would guide the development of the PCM. In addition, the Commission directed ERCOT to evaluate bridging options to retain existing assets and build new dispatchable generation until the PCM can be fully implemented. However, the Commission directed Commission staff and ERCOT to delay implementation of the PCM until such time as the Legislature has had an opportunity to render judgment on the merits of the PCM or establish an alternative solution.
That same day, the Chairman of the Texas Senate Business and Commerce Committee issued a letter disapproving of the Commission’s adoption of the PCM design, calling it “a substantial departure from the legislative intent of SB 3, specifically Section 18, which relates to the development and procurement of a new ancillary or reliability service to incentivize new dispatchable generation.” The Chairman characterized the PCM as “an unnecessarily complex, capacity-style design that puts the competitive market at risk without guaranteeing the delivery of new dispatchable generation.” The Committee held a hearing on the matter on February 7, 2023, but has not yet taken action or proposed any legislation.
Performance Credit Mechanism
The PCM would be a new model that has not been implemented in any electricity market in the world. Under the PCM, load serving entities (“LSEs”) would be required to purchase “performance credits” earned by generators based on their actual availability to the system during the hours of highest risk in a particular compliance period. ERCOT would determine the total number of MWh that it expects would be available during the anticipated hours of highest reliability risk for a system that meets the 0.1 days/year loss of load reliability standard.
After the operating year, ERCOT would award generators one credit for each hour within the hours of highest risk that the generator offered a megawatt of capacity into the energy or ancillary services market. Credits would be priced based on a demand curve developed by ERCOT (adjusted every year) to allow generators to yield revenue equal to the net cost of new entry per unit of effective capacity offered. The total cost of all credits would be allocated amongst LSEs based on their actual pro-rata share of system demand across those same hours.
In addition to this year-end settlement process, ERCOT would also administer a centrally cleared voluntary forward market for LSEs and generators to exchange credits to hedge against potential adverse outcomes in the retroactive settlement process. E3 noted the risk that actual quantities of credits produced may differ from forward offers. Transactions in the forward market would be voluntary, but generators would be required to participate in the forward market to be eligible to participate in the retroactive credit settlement process.
Because the number of credits is fixed based on actual generator availability much of the pricing mechanism relies on the shape of the ERCOT-set demand curve. E3 stated that the demand curve should be developed with an eye towards three goals:
- Induce entry of new generation into the market;
- Be “self-correcting” and aligned with economic principles; and
- Provide some level of price stability.
Each year ERCOT would be able to tweak the curve to incorporate trends in resource availability and load growth. Nevertheless, the curve would be set ahead of the operating year, and therefore may not fully capture a given year’s circumstances.
In addition, because a reliable system must retain resources for availability during less frequent extreme events, the credit requirement must be higher than the sum of energy and operating reserve requirements during critical periods in many years. E3 noted that the credit requirement would thereby provide a stable revenue stream to generators even in years when scarcity situations do not arise in the energy and ancillary services market.
E3 projected that new generation incented by the PCM would reduce the frequency of scarcity pricing events, reducing the energy and ancillary service costs borne by LSEs. But those reduced costs would be at least partly offset by the cost to procure credits.
Market Design Alternatives
While the Commission has voted to move forward with the PCM market design, its ultimate implementation is far from assured. Many market stakeholders, including the ERCOT Independent Market Monitor (“IMM”), do not support any of the six market designs that E3 evaluated.
Indeed, the IMM noted that the Commission has already adopted significant changes to the energy-only market design by implementing adjustments to the Operating Reserve Demand Curve that would likely incent the development of dispatchable resources, and that such changes are likely to provide more meaningful incentives than any of the market design proposals under consideration. It also argued that E3’s analysis is predicated on 11 GW of existing resources retiring in the coming years, an assumption the IMM called unsupportable and inconsistent with generators’ economic incentives. Ultimately, the IMM found the PCM proposal to be a less effective and efficient means to facilitate performance by ERCOT’s generation than the existing energy-only market. The IMM predicted that uncertainty about when performance credit measurement hours will occur might cause market participants to behave inefficiently by reducing load or committing uneconomic generation when PC hours are predicted but do not materialize.
Prior to the E3 report, the IMM had proposed the development of a 2-4 hour uncertainty product that could be deployed to start up longer lead-time units when ERCOT detects that operating conditions are departing from expected conditions (i.e. the uncertainty that is inherent in forecasting or in thermal forced outage expectations). This is because the IMM believes that the issue facing the ERCOT market going forward is operational flexibility, not resource adequacy. The product would be procured in the day-ahead market based on factors such as intermittent renewable generation, load forecast error, and thermal generation forced outage probabilities.
A large coalition of 29 commenters proposed a Dispatchable Reliability Reserve Service (“DRRS”) as a PCM alternative. The proposed DRRS would be an uncertainty product like the one previously proposed by ERCOT’s IMM. Like the IMM’s proposed uncertainty product, the DRRS would be procured the day ahead, and would be intended to ensure dispatchable generation was available in real time to cover for the uncertainty around renewable generation variability, load variability and unforeseen thermal forced outages. Eligible resources would be available in real-time to be dispatched within two hours of deployment, and would be able to continue to provide the service for 4 hours. DRRS’s advocates argue that it would create an additional revenue stream for flexible dispatchable resources, helping to retain existing resources and over time sending price signals to develop and build new flexible dispatchable generation, storage, and demand response resources.
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