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Texas Retail Provider: PCM Design Includes "Crap Shoot" Element

Another REP: PCM's Increased Financial Requirements, Switching Risk Would Force Retail Market Consolidation, Result In "Gentailer Monopsony"

TEAM: PCM Design Makes Fixed Price Retail Contracts Infeasible

December 15, 2022

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Copyright 2010-21
Reporting by Paul Ring •

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Texas stakeholders filed comments at the PUC on a proposed novel Performance Credit Mechanism [PCM] as a means to achieve ERCOT reliability

See background on the PCM here

As first reported by, a group of independent REPs, including Shell, along with large customers, NOIEs, and renewable energy companies, have filed a proposal for a Dispatchable Reliability Reserve Service (DRRS) (built on the Uncertainty Product advocated by the ERCOT IMM) as the best mechanism to ensure the supply of reliable and affordable electricity (see details here)

David Energy Supply (Texas), LLC warned that the impact of increased financial assurance requirements under the PCM and the creation of a brand-new retail switching risk, "will disproportionally negatively impact small REPs, ultimately resulting in further REP consolidation, likely resulting in ERCOT's current competitive retail market into a gentailer monopsony."

David Energy said that the PCM, "would significantly increase capital requirements for retailers by increasing ERCOT collateral requirements to cover PCM exposure."

"The proposed design fails to address the impact of the PCM on collateral requirements for ERCOT market participants. In ERCOT, collateral requirements are based on a participant' s market activity and are intended to cover the risk of unpaid invoices. Invoices are currently settled daily. In the PCM design, a significant portion of annual energy costs would be invoiced in a single annual look-back settlement. This means that REPs would have to post, not only the collateral for daily invoices, but also increasing amounts of collateral over the course of each year to cover the PCM settlement for the current year, but not invoiced until the following year," David Energy said

David Energy further said that the PCM would create a new retail-switching risk, "that would require REPs to increase rates, and simultaneously increase the risk that REPs are unable to pay ERCOT invoices due to customer nonpayment of bills."

"The proposed PCM design also fails to address the impact that customer switching will have on the ability of REPs to recover PCM costs attributable to retail customers who switch to another retailer after creating PCM exposure for that REP, but before the PCM look-back settlement. This would be an entirely new risk that REPs would need to mitigate. Even if REP customer contracts could allow for such invoicing post contract termination, it would surely result in a higher rate of customer nonpayment which would require REPs to price that risk into energy rates. The current PCM proposal does not contemplate the scale of such rate increases, or their impact to consumers. Increasing customer rates to account for this nonpayment risk would not fully mitigate the risk and could, in fact, increase the potential for monthly energy bill nonpayment. Additionally, if the contracts cannot guarantee PCM payment post termination or are otherwise difficult to enforce, customers whose contract termination fees are less than their expected PCM exposure will have the perverse incentive to terminate the contract and switch retailers rather than pay their current REP for last year' s PCM charges. With increased customer nonpayment, REPs would risk not being able to pay ERCOT PCM invoices, thereby perpetuating the need for large financial assurance requirements," David Energy said

"The impact of such increased financial assurance requirements and the imposition of a brand-new retail switching risk will disproportionally negatively impact small REPs, ultimately resulting in further REP consolidation, likely resulting in ERCOT's current competitive retail market into a gentailer monopsony," David Energy said

"All options in the E3 evaluation are evaluated based on fatally flawed, unrealistic, assumptions. These include assuming availability of unlimited gas in all weather conditions, assuming mass amounts of generation retirements without support or precedent, and assuming weather conditions that do not depart from those experienced between 1980 and 2019 -- specifically excluding the weather conditions in 2021 during Winter Storm Uri that instigated these proceedings, and those experienced since Uri in 2022," David Energy said

In separately filed comments, Octopus Energy cited a "crap shoot" element to the PCM, specifically referring to the 30 [or other chosen number] hours used to establish the hours in which LSEs were required to have PC credits

"The reliance on payments to generators during these potential high-risk hours - in whatever quantity, 30 hours or otherwise - is a fundamental flaw of the PCM. As proposed, ERCOT would predict 'X' potential hours one year in advance and estimate the expected load to be served during those hours to develop the pricing curve, and then after the operational year, the market would learn when the PCM hours actually happened and how much load actually needed to be served during those hours," Octopus Energy said

"This mechanism takes a capacity market construct - which does not address the problem at hand - and then adds a 'crap shoot' element to it, by requiring both generators and REPs to guess when the 30 hours might occur," Octopus Energy said

"From Octopus Energy's perspective as a REP unaffiliated with any thermal power generation companies in Texas, the PCM as proposed is unworkable. The PCM would create a level of uncertainty and risk that REPs -- at least those unaffiliated with generators -- cannot adequately hedge," Octopus Energy said

Octopus Energy does not support adoption of the PCM. However, to the extent the PUC elects to adopt the PCM, Octopus said that the period over which the hours of highest reliability risk are determined should be shortened from the proposed annual period

"The proposed annual interval creates an insurmountable challenge for a REP (and by extension, its customers) to discern when it would need to take action to reduce consumption to avoid the assignment of PCM costs ... [M] many of the hours of highest risk will be those hours when thermal generators break down and must take unplanned outages, and those times cannot be predicted as they may happen during any hour of the year, unrelated to extreme weather or peak net load. As a practical matter, this means that a REP will be asking customers to reduce consumption at times that will make no intuitive sense to the customer. Additionally, it would be the following year/month/week/etc. when the REP would know whether the requested load reductions coincided with the actual 30 hours of highest risk. It would be almost impossible for the REP to properly charge or credit customers for their consumption behavior related to those 30 hours based on retroactive settlements. This lack of proper alignment of incentives to induce customer behavior with the times when it is most beneficial to the grid is a major flaw to the PCM market design and creates significant new barriers to demand response and other distributed energy resources (DERs)," Octopus said

Octopus suggested a daily implementation of the PCM to the extent the PUC adopted a PCM design.

"In a daily implementation of the PCM, the Commission could administratively predetermine a value of the PCs at the beginning of the year, which would provide transparency and certainty for the value of the credits. For example, the Commission could determine the gross value of compensation it wants to distribute through this methodology and divide by 365 to determine the daily compensation to be made available. Then, credits could be awarded to generators who perform that day (by providing energy or ancillary services) during the designated hour of concern for the operating day. This also would make it more possible for REPs to have the ability to buy adequate credits to meet their obligations during those hours, manage their load to reduce their exposure to the cost of credits during those hours, and even incorporate the expected cost of credits into retail pricing to which would allow the REP to continue to offer fixed price contracts to customers," Octopus said

"As proposed, the annual PCM severely disadvantages REPs who are unaffiliated with generation. Simply using a centrally cleared market does not mitigate the potential for market abuse. When an affiliated REP buys from its affiliated generator, that is essentially just moving money 'from one pocket to another pocket,' but unaffiliated REPs would have to buy PCs from a handful of generators with oligopoly power. As with monopolies, oligopolies are characterized as having the ability to strongly influence prices. Similarly, those handful of generators have affiliated REPs that wield oligopsony power, i.e., they are a handful of major buyers in the market that control the purchasing of PCs. It's not difficult to imagine a situation where an oligopoly generator may be able to share information with its affiliate REP so that the REP is better able to respond through customer demand response measures to meet some of the 30 hours of highest risk, and then the REP can resell its excess PCs to an unaffiliated REP for a profit, meaning that the PC is sold twice by the same family of companies. Moving to a daily market would also reduce these risks, especially if the price for each credit to be earned is known ahead of time through a set price established by ERCOT administratively," Octopus said

In separately filed comments, Texas Energy Association for Marketers (TEAM) said that the PCM as proposed in the E3 report, "appears to make it infeasible to offer fixed price contracts for residential and small commercial customers unless prices for protected customer classes will be subject to adjustments based on changes in the cost of the capacity credits throughout the term of a contract."

"A retroactive determination of reliability hours is not consistent with a competitive retail electricity market," TEAM said

"The PCM will increase customer costs and will decrease options for customers-both in terms of innovation and number of REPs who are able to offer service in ERCOT," TEAM said

"In addition, it is not a reasonable expectation to assume a pure economic pass-through of the direct cost of the Performance Credits. A REP would also incur costs that are less transparent such as the cost of collateral postings that will be required for expected performance credit obligations; increasing the costs to serve customers in ERCOT. If a REP buys the credits on a forward exchange, there is a requirement for those credits to be paid for in advance, before the customer receives service, or a collateral will have to be posted to the seller to account for future fluctuations in prices. If the REP is unable to buy the credits on a forward basis, it is expected that ERCOT would add the cost of performance capital credits to the collateral requirements for all LSEs. Depending on the calculation, this would increase the cost to serve customers and could be cost prohibitive for REPs and other LSEs who do not have an affiliated interest that supplies sufficient credits to match the projected load of the LSE. These collateral costs will determine the feasibility of a market participant to remain in the market and offer service to customers," TEAM said

"Under the current wholesale and retail market constructs, a REP is able to manage collateral costs at ERCOT with firm scheduling of power through a bilateral agreement. While REPs are able to enter into wholesale energy supply contracts to match the term of the customer' s fixed price contracts in today's market design, the upfront collateral is often mitigated by a right of the wholesale supplier to assume the retail customer contract as collateral. This has economic rationality because the customer' s retail contract corresponds in timing and quantity to the wholesale energy purchase. However, the PCM obligation does not directly correlate to the customer's usage because the settlement interval (i.e., day and time) that the obligation will be measured is unknown at the time of execution of the contract with the customer. In fact, the PCM obligation, in both quantity and price, remains unknown even after the customer is provided service and billed for usage. The look-back feature of the PCM to determine the obligation and the price adds risk and cost for the credits and the associated collateral," TEAM said

TEAM said that, "The PCM design in the E3 Report is not consistent with the legislative language in Senate Bill 3, which directs the Commission to ensure that ERCOT procures ancillary and/or reliability services that meet the reliability needs determined by ERCOT. In contrast, the PCM design does not appear to contemplate a procurement of a service by ERCOT and instead puts a capacity obligation on each customer serving entity."

TEAM further said that, "As laid out in the E3 report, the centrally cleared market does not mitigate market power concerns. It does not address market power concerns because there is not a must offer component. E3 has indicated that there is not a mandate for quantity or price in the forward market. Therefore, it is expected that the residual market will be the primary place where these capacity credits will made available and clear. For an LSE that does not also have a portfolio of dispatchable generation, this mechanism creates significant financial exposure that could not be tolerated. Essentially, LSE's that don't have affiliates that own generation will be left to pay for capacity credits after the reliability period based on their customers' actual usage along the sloped demand curve that is administratively determined by the Commission."

In separately filed comments, Shell Energy North America (US) LP detailed higher costs to customers under the PCM

"The PCM would create significant increases in costs to consumers due to multiple factors. The increased cost from capacity market constructs as estimated in the E3 report is $5.7 billion, which will be on top of Energy and Ancillary Service costs for the first year. The cost will reach $460M only after the system reaches the equilibrium state, which could take several years. If 2021 is used as the representative cost year (excluding extreme outcomes from Winter Storm Uri), the IMM State of the Market report lists the average ERCOT real-time energy market price for 2021 as $40.73/MWh. The $5.7 billion capacity market cost spread across the 2021 total of 393 billion kilowatt-hours consumed would result in an additional $14.50/MWh, which is a significant increase of 35.6% on top of the prevailing energy price. Based on the value estimated by ICF report, the capacity procurement will result in additional $21.63/MWh, which is a significant increase of 53.1% on top of the applicable energy price. Furthermore, there will be even more cost burdens borne by consumers due to the added risk and uncertainty inherent in the design of the PCM," Shell said

In separately filed comments, the Independent Market Monitor for the wholesale market in the ERCOT region stated, "We find that the PCM proposal is a less effective and efficient means to facilitate performance by ERCOT' s generation than the energy-only market," as the IMM again proposed its previously reported "uncertainty" product

"The primary reliability issue that we identify associated with the rapid increase in intermittent generation is one of operational flexibility. To address this issue, we continue to recommend, as we did in our October 15,2021, comments, that ERCOT adopt a 2- to 4- hour uncertainty product.3 Such a product can be deployed to start up longer lead-time units when ERCOT detects that operating conditions are departing from expected conditions (i.e., the "uncertainty" inherent in forecasting models or in thermal forced outage expectations)," the IMM said

"One can think of the uncertainty product as non-spinning reserve service (non-spin) with a longer start time requirement. However, the pool of resources that would qualify for the uncertainty product (including demand response) will be higher than the pool for non-spin and therefore the competition to provide it will be stronger in the uncertainty product market," the IMM said

"Given the magnitude of the Phase I changes and the drawbacks and costs of Phase II proposals, we do not recommend that the Commission move forward with any of the Phase II proposals. We believe the current market will produce revenues sufficient to prevent the widespread retirements predicted in the Report and will incent investment in new dispatchable generation," the IMM said

In its comments, the IMM addressed what it called, "flawed analytic criteria employed by E3," with the IMM stating that, "correcting this allows us to conclude that the current market will likely continue to more than satisfy the 1 in 10 reliability criteria cited in the Report."

In separately filed comments, NRG Energy Inc. recommended that the Commission, ERCOT, and market participants, "focus on the implementation of the PCM as the ultimate solution for long-term reliability in ERCOT."

"The PCM meets the requirements of SB3 by providing a market construct to ensure sufficient dispatchable generation and demand response to meet a reliability standard," NRG said

NRG said new ancillary services, including an "uncertainty" product, would not solve the reliability problem

"Notably, in times of grid stress after Winter Storm Uri, nearly all generation resources were already online and operating. A new 'uncertainty' product in such conditions would have nothing to procure, and it is fanciful to believe such a service would meaningfully promote new investments. Ancillary services do not get new generation built," NRG said

"While NRG is still evaluating the specific details of the PCM proposal, the concept meets statutory requirements and the Commission's principles, and provides a significant improvement in the necessary incentives for reliability. NRG recommends the PUCT set a policy direction to implement PCM by June 1, 2025, focusing stakeholders on reviewing and working through the design details," NRG said.

In separately filed comments, Vistra Corp. likewise took aim at new ancillary services or other similar options being offered as the solution for reliability

"The advocates for more operational band-aids, such as a vaguely defined and unstudied 'uncertainty product' or 'dispatchable reliability reserve service,' have expressly stated that 'there is no capacity problem.' In other words, they deny the PUC's and Legislature' s assessment that more capacity is needed and reject ERCOT CEO Vegas's statement that there is a capacity shortfall. In turn, they also flatly disagree with the Legislature and the Commission that the fundamental goal is to get more dispatchable generation capacity built. Accordingly, their proposed 'solutions' are aimed at a different problem, and their proposed criticisms are not valid measures for judging whether a proposed construct will lead to more dispatchable generation construction, since that is a goal they do not support," Vistra said

"Further, simply buying more ancillary services -- such as an amorphous 'uncertainty product' -- will not solve the problem policymakers have identified. Buying more ancillary services from existing generation units will not incentivize (and has not incentivized) building new, incremental dispatchable generation. Vistra is unaware of any ancillary service change, either through the development of new products or increased procurements, that has on its own led to increased generation facility development. In fact, it will worsen the situation, further suppressing the on-peak prices that are supposed to signal the need for, and support, generation investment. Vistra has discussed potential new generation development confidentially with possible investors. When asked, none of them stated they would invest in new generation in ERCOT as a result of more or different ancillary service products. If ancillary services were a driver of investment, then ERCOT' s recent increased procurements would be providing such incentives right now and we should see announcements for new build now-but they are not; hence, a different approach is essential. Tellingly, none of the proponents of the 'uncertainty product' have stated that they would look to build new dispatchable generation if their proposal is adopted," Vistra said

Vistra added that, "ERCOT is home to the most successful competitive retail electricity market in the world, where each consumer is empowered to choose the services and features they value in their electricity service ... A well-designed PCM can do this as it preserves the competitive nature of the energy market, which will still be the heart of the Texas electricity framework."

In separately filed comments, Calpine stated, "Calpine believes PCM call put policy makers in control of the level of reliability they want to achieve through adoption of a standard that is linked to a demand curve. The PCM includes many favorable attributes, can be technology-neutral and non-discriminatory, and will create incentives for customers to reduce costs through demand response during key measurement periods."

In separately filed comments, NextEra Energy Resources, LLC said that it, "believes that all of the market design options presented in the E3 analysis have some level of merit," but further said, "Of the various designs in E3's analysis, NextEra sees the Performance Credit Mechanism (PCM) as providing a level of certainty that will not only keep existing generation online but will also give certainty to the market allowing for the financeability of new generation being built."

However, NextEra offered some changes to the PCM, including the period over which the hours of highest reliability risk are determined, and cited market power concerns.

"NextEra believes that more certainty for generators, and retail entities, could be achieved through the adoption of multiple, shorter compliance periods. There is opportunity for better forecast predictions on a monthly basis and would be easier for entities to manage, which is also obtainable on a seasonal basis. An annual interval could prove too open ended which would create more uncertainty, which is the opposite goal and intent of these market changes," NextEra said

Additionally, NextEra said, "Centralized clearing alone, in a market in which LSE's [sic] are required to purchase Performance Credits, is not sufficient to mitigate market power without additional controls on generation resource offers. Furthermore, to ensure retail competition is preserved it would be imperative that bilateral agreements between generation owner and retail affiliates are not allowed and thus generators would be required to offer 100% into the market. This is the best way to ensure a level playing field for all retailers to participate in the market. The goal is that there would not be any favoritism and ultimately the end customer will benefit. Using a centralized clearing on a downward sloping demand curve in combination with offer mitigation based on recovery of go-forward costs should be sufficient to mitigate market power abuse in the centrally cleared portion of the market."

In separately filed comments, Constellation Energy Generation, LLC stated that it, "recommends that the Commission direct ERCOT to implement the Performance Credit Mechanism ('PCM')."

In separately filed comments, the Alliance for Retail Markets said that a mechanism such as PCM can help ensure reliability and stability of the ERCOT market

"ARM believes that a long-term load-side reliability solution, such as the Performance Credit Mechanism ('PCM'), can help ensure reliability and stability of the ERCOT market."

"The biggest threat to the continuation of the competitive retail market is reliability risk and the recurrence of grid outages," ARM said

"Patchwork fixes (e.g., increasing procurement of ancillary services and Reliability Unit Commitment utilization) may shore up reliability in the shorter term but may create negative long-term reliability consequences and lead to higher prices for customers. Consequently, the sooner the Commission concludes its evaluation of Phase II market design proposals, the sooner REPs can plan for the future to help ensure the prices REPs offer customers are realistic and as stable as possible," ARM said

"However, the market design that the Commission adopts must be reasonably predictable and transparent to market participants in order to enable REPs to manage risk and provide customers the best service at the lowest cost. The PCM can achieve this by utilizing a flatter, rather than steeper, demand curve; utilizing a seasonal rather than annual cadence; communicating the demand curve well in advance of the forward market; incorporating policies that encourage forward market participation; and allowing for bilateral trades to supplement the forward market. These refinements will reduce volatility in the PCM outcomes while allowing REPs to manage their financial risks associated with the PCM," ARM said

"As an aside, ARM is aware of certain stakeholders arguing that the PCM is akin to a 'capacity market' and that it is incompatible with retail competition because other regions with such constructs have weak retail competition. Such arguments are red herrings. First, the PCM is not a traditional capacity market seen ill other regions, as it is at its core a 'pay for performance' construct. Second, other regions have struggled with retail competition not because of their market designs, but rather because of other policies that stifle customer choice, such as continued default service under the vertically integrated utility and relegating retail choice to a line item on that utility's bill instead of allowing the REP to fully own the customer experience through supplier consolidated billing. These barriers preclude those markets from unlocking innovative offerings that utilities' billing platforms cannot support. Finally, arguments that the PCM would harm retail choice or be 'too risky' for REPs are unfounded; the competitive retail market in ERCOT has survived many market design reforms and will continue to do so under PCM," ARM said

In separately filed comments, ERCOT said that ERCOT estimates that the PCM implementation would cost between $2 and $4 million with an estimated project duration of between 1.5 and 2.5 years. This estimate assumes project work would be concurrent with RTC-related work. Also, this project duration would be in addition to the time needed to develop necessary PUC rules and ERCOT Protocols, ERCOT said

ERCOT anticipates an overall rule development phase between 6 months and 1 year which would likely start after completion of the upcoming Texas legislative session.

"This brings the total estimated duration for delivery of PCM to between 2 and 3.5 years after PUC direction to move forward," ERCOT said

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