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ERCOT stakeholders divided on price reform

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ERCOT stakeholders divided on price reform

Despite the expected retirement in the Electric Reliability Council of Texas of as much as 4,600 MW of generation this winter, most intervenors commenting on the Public Utility Commission of Texas' project to address ERCOT pricing issues said regulators should proceed with reforms.

On Nov. 30 and Dec. 1, 21 entities filed 228 pages of comments in the PUCT's Project No. 47199, "Project to Assess Price-Formation Rules in ERCOT's Energy-Only Market," which was established in response to a paper written by William Hogan, the Raymond Plank professor of global energy policy at Harvard's John F. Kennedy School of Government, and Susan Pope of FTI Consulting for NRG Energy Inc. and Calpine Corp., who submitted the report in May to the commission.

The Hogan-Pope paper's recommendations included:

* Including marginal line losses in calculations used to determine which generation units to dispatch to supply load.

* Establishing local reserve requirements.

* Creating local operating reserve demand curves, which provide an adder to energy prices as operating reserves decrease and the probability of load loss increases.

PUC staff conducted a workshop on the project Oct. 13, and the PUC decided Oct. 26 that they wanted the intervenors to submit written comments by Dec. 1 addressing seven questions.

'Market is hemorrhaging'

One of the questions asked whether the PUC should "defer certain changes to the market design to observe market dynamics over Summer 2018 or longer," given the planned retirement of as much as 4,600 MW of generation between December 2017 and February 2018.

The position of the South Texas Electric Cooperative Inc. was unequivocal. The utility in its comments cited bankruptcies as evidence that "the market is hemorrhaging."

On Nov. 7, Exelon Corp. affiliate ExGen Texas Power LLC filed for protection under Chapter 11 of the U.S. Bankruptcy Code, affecting about 3,500 MW of capacity in Texas.

"Before reserves dip below unpalatable levels, the Commission should address these known issues now," South Texas said.

Calpine aid in its comments that "ERCOT reserve margins are now projected to fall into the single digits."

"The sudden and sharp drop in projected ERCOT capacity makes this a precipitous time for the Commission to investigate and move forward with market rule improvements so as to ensure the market will timely and appropriately replace this vital capacity," Calpine said.

However, others, including the Environmental Defense Fund, ERCOT Steel Mills, Invenergy LLC and Texas Industrial Energy Consumers, or TIEC, said now is not the time to implement significant market design changes.

"ERCOT has had surplus reserves for the past several years, and the vast majority of the market reforms adopted since 2012 have never been tested under tight conditions," TIEC said in its comments. "Appropriate scarcity pricing is critical to the long-term health of the ERCOT market, and the Commission should allow the scarcity pricing regime that has been put in place to work. The Commission should anticipate higher prices with tighter reserves, and should allow such prices to incentivize additional investment."

Real-time co-optimization supported

The PUC staff asked in its first question what market design reforms are necessary "to support efficient investment and retirement decisions" in ERCOT. Aside from those who said no such reforms are necessary, the following proposals were highlighted by the most respondents:

* Seven for real-time co-optimization of energy and ancillary service markets.

* Seven for eliminating energy supplied by reliability must-run and reliability unit-committed resources from operating reserve calculations.

* Four for shifting the loss-of-load probability curve used in the operating reserve demand curve so larger price adders would be generated with larger reserves, which would effectively recognize the enhanced risk of greater intermittent generation totals in the system.

* Four for including marginal line losses in calculations used in dispatching energy.

Several intervenors who advocated a "go-slow" approach on price formation reform said building more transmission would solve many of the reliability problems that might arise as reserve margins dwindle, but NRG Energy said in its comments that the transmission system construction has ballooned from $760 million per year for 2006 through 2010 to $1.1 billion per year for 2011 through 2017 and is expected to average $1.2 billion per year for 2018 through 2020.

"The failure of locational energy prices to incentivize sufficient response and appropriate siting decisions is likely a contributing factor to the increased transmission cost," NRG said. "Improving locational price formation mechanisms will help establish more of a balance between market investment and regulated transmission development."

Mark Watson is a reporter for S&P Global Platts, which, like S&P Global Market Intelligence, is owned by S&P Global Inc.