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TEAM: Focusing On Scarcity Pricing Frequency In Evaluating ERCOT Market Performance, Resource Adequacy Provides Incomplete Picture

September 17, 2018

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Copyright 2010-17
Reporting by Paul Ring •

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In comments to the Texas PUC concerning ERCOT summer market performance, the Texas Energy Association for Marketers (TEAM), in responding to a specific question concerning whether scarcity pricing produced sufficient revenue to ensure resource adequacy, stated, "If the Commission decides that an examination of long-term resource adequacy in the ERCOT region -- i.e., whether the current competitive market design is able to provide the market with sufficient price signals to maintain an adequate reserve margin in ERCOT -- is appropriate, that examination should be broader than the above stated question implies. As worded, Question No. 1 is premised on a faulty presumption that scarcity pricing mechanisms are the sole means by which generators are compensated for their services. In actuality, the amount of energy purchased in real time through scarcity pricing mechanisms constitutes only a small percentage of the total amount of revenues received by owners of generation resources."

"In ensuring that they will have the ability to meet the power supply needs of their end-use customers, retail electric providers ('REPs') purchase the majority of this power directly from generators (or power marketers) through bi-lateral agreements. These agreements are entered into for years, months, or days before the operating day in which the power is delivered. In addition, REPs incur costs for ancillary services paid to the owners of generation. It is also common for REPs to pay generators in other forms, such as purchasing call and put options, to ensure that the REP has the ability to economically provide power to their customers outside the real-time scarcity pricing mechanisms. As such, an inquiry focused solely on scarcity pricing mechanisms would not present the Commission with sufficient information to evaluate whether or not the market is working in a manner sufficient to allow competitive market forces to ensure the adequacy of supply to meet load in the ERCOT market in the long-term," TEAM said in its comments

"Examination of the performance of real time scarcity pricing mechanisms in isolation are insufficient to determine whether generators are incentivized to build generation. For the entirety of 2018, the forward curves for power purchases during anticipated scarcity in August demonstrate significant cost increases," TEAM said

TEAM attached to its comments the pricing for the August forward curves as presented to the ERCOT Board for 2018. TEAM said that such data shows that, "the bilateral cost of power available for summer of 2018 properly reflected scarcity and increased revenues to generators in bilateral contracts."

"For new customers who enrolled with a REP in the Spring of 2018, the cost to the REP to enter into a bilateral contract to purchase peak power to meet the load for that customer in August was in the range of $200 per MWh. Even though real time prices in August were generally less, the generator who contracted to sell that power in the Spring would have been paid much more than the real-time price," TEAM said

"In addition to this cost, REPs paid generators for ancillary service costs which also increased over the Summer of 2018. There is no indication that the ERCOT region lacks sufficient resource adequacy. In the Summer of 2018, there was never an emergency event called by ERCOT. The market performed in accordance with that fact. There were several intervals where the day-ahead market did reflect prices that indicated an anticipation of resource scarcity. Further, there are indications that additional demand response is available to reduce load in the market should there be actual scarcity of generation availability. In each of those instances, the load forecasted in the day-ahead market did not materialize," TEAM said

"ERCOT reports indicate that new generation is currently being added to the ERCOT region. Should market forces indicate that additional generation is needed, there are a myriad of projects that appear ready to go to meet those needs," TEAM said

Texas Industrial Energy Consumers (TIEC) similarly noted that real-time market prices are just one of the many revenue streams available to generators in ERCOT. "PNM measures only realized real-time prices -- not Day- Ahead Market (DAM) revenues, margins from bilateral contracts, profits from futures markets, ancillary service payments, or other important revenue streams available to generation companies. It is not necessary to depend on real-time prices alone to support new entry," TIEC said

Furthermore, TIEC said, "The complex deregulated market in ERCOT also provides incentives for generators and load serving entities to hedge their own financial risks by affiliating wholesale generation and retail market businesses. This can provide additional revenue that is reinvested in generation development (or new demand response products) when the market conditions are right."

Citing recent presentations to investors, TIEC said, "For instance, Vistra has noted that integrating its generation and wholesale businesses operations raises margins by $3-$4/MWh, while leading to more stable cash flows by avoiding mark-ups (bid-to-ask spreads) and eliminating the need to post collateral. Vistra has also recognized that it can optimize the value of its portfolio through hedging, with its actual realized power price being far higher than real-time prices. Additionally, Vistra has acknowledged the earnings stability created by its integrated generation and retail platform, and that its retail margins are also a hedge for its generation business. Similarly, NRG Energy touts its Improved Business Platform as an integrated business model that is customer-driven. NRG discusses how it has right-sized its generation fleet to more closely match its retail profile, which will lead to more stable margins and an attractive market."

In contrast, Vistra Energy Corp. said that, "the forward market responded negatively to the overall lack of revenues during a summer that was expected to be tight, and current forward prices do not support the rational development of any new resources in ERCOT."

"In short, the current ORDC scarcity pricing mechanism creates the threat of very high prices, but those prices have rarely materialized in the real-time market, contributing to backwardation of forward power curves (which drive resource investment and retirement decisions); a disincentive for Retail Electric Providers (REPs) to hedge; and large unit contingency risks for generators that incentivize generators to retain portfolio length instead of offering that capacity for forward sales (further exacerbating the disincentive for REPs to hedge)," Vistra said

"The relative rarity of price adder formation in the real-time market is a hindrance to forward price formation, because real-time outcomes drive forward price expectations, and experience has shown a significant recency bias in forward curves. That is, the most recent real-time pricing outcomes tend to have an outsized impact on forward price formation relative to the totality of factors driving future real-time price outcome probabilities. This is evidenced by the declining forward price expectations for 2019 to 2022 ... following the relatively poor performance of the scarcity pricing mechanism over the summer 2018. For example, across several periods this past summer where market conditions were expected to be particularly tight, intraday trading saw some significant upward volatility that at times coincided with upward swings in summer 2019 peak prices -- but as the summer months passed demonstrating predominantly lackluster pricing, summer 2019 peak prices fell significantly (but notably still not converging with the more real-time pricing)," Vistra said

Texas Competitive Power Advocates (TCPA) sought the following changes to the ORDC.

• Increasing the Loss of Load Probability by shifting the mean by 1 standard deviation

• Simplifying the ORDC calculation by eliminating the seasonal and time of day variation in the LOLP determination. pricing.

In addition to these changes, Calpine also sought to change the minimum contingency level ("X") to set "X" equal to 2,600 MW.

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