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ERCOT Generators Plea for "Help" from PUCT
June 30, 2011
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Calls for various changes in the ERCOT energy-only market design amount to generators seeking "help" from the PUCT in building new generation.
Speaking during a PUCT workshop yesterday, Randy Jones, vice president of market design for Calpine, said that the deployment of Non-Spinning Reserve Service (NSRS) has a significant downward impact on energy market prices. A key principle of the deregulated wholesale market, Jones said, is that generation companies take on the risk of build out, while in exchange load takes on the price risk.
Citing the price depression effect of Non-Spin, Jones said that, "[i]t's clear from this data that, due to the actions of the ISO, inadvertently the loads are being helped to handle their price risk. And our question is, where's the help for the generation side to handle the risk of expansion in the system."
Jones continued:
"We implemented this market with the objective function of trying to optimize the real-time market and to provide the lowest cost to consumers, while at the same time hoping that we would contribute enough revenue stream to generators to continue to provide long-term adequacy. Those two motives seem to be at odds, and it seems that the more you drive optimization in the market, the more likely you are to not have long-term adequacy without some kind of mechanism that creates adequacy in the long-term.
"When you have a paradigm like we have where you have a bifurcated market with those who have bundled load still assigned to them, it seems obvious at this point after the history in the market that those are the only folks who can handle the risk of project development because they do it on the backs of their consumers," Jones said.
However, Philip Oldham of the Texas Industrial Energy Consumers said that the market is seeing forward prices trend in the right direction for resource adequacy.
Oldham said that he talked with a number of market contracts in ERCOT ahead of the workshop, and said, "[t]here's a real question about whether you fundamentally believe that some generators, and others who have a vested stake in perhaps pricing outcomes, are right, or rather the market as a whole is right. The truth is when I probed yesterday, a lot of folks said we don't need any new power plants until 2014 or 2015 and the reason is we have lots of mothballed capacity; the NOIEs [Non Opt-In Entities, the munis and co-ops] are building generation, to serve loads that are adding to the NOIE system; and so that new load growth is not really in the competitive market, therefore we don't need these generators necessarily to be building capacity to serve it."
"It's hard to talk to these folks who do this for a living and believe that they're not taking all of that into account in terms of pricing forward contracts ... I fundamentally believe they are very smart, they do see what the needs are going forward, they run those models all the time, and the market has continued to respond with the right amount of build," Oldham said.
Addressing various potential solutions, PUCT Chairman Barry Smitherman cited each of the Commissioners' prior record comments regarding capacity markets or payments [which range from skepticism to opposition], and said, "I don't suspect that we're going to move away," from those positions.
Commissioner Kenneth Anderson concurred that, "I don't think there's any appetite for here for capacity payments."
Rather, Smitherman said that the Commission is interested in making design changes at the margins, and noted there seems to be a consensus regarding a preference to use Non-Spin instead of Reliability Unit Commitment (RUC).
Bob Helton, vice president of regulatory and legislative affairs for IPR - GDF SUEZ North America, said that Non-Spin is a more competitive product than RUC, and does not include the distorting signals which result from the RUC "clawback" paid to load, which alleviates load from the costs of being short in the market. Helton also suggested removing the cap on Non-Spin so it may be used more often instead of RUC.
Commissioner Donna Nelson was not prepared to order ERCOT to undertake any Non-Spin changes at the workshop, but said that the Commission should discuss it at an open meeting. Commissioners agreed to address the issue at the July 8 meeting.
Smitherman also said that the next issue to address may be a look-ahead Security Constrained Economic Dispatch (SCED), though he noted this term is not well defined. Smitherman said that there may be value in prices that last for more than one interval, so that scarcity prices do not collapse just as a generator responding to such signals comes online. Proposals for look-ahead SCED have not included binding look-ahead LMPs, but potentially could include a Revenue Sufficiency Guarantee to generators committing as a result of the look-ahead.
Eric Goff, manager of regulatory affairs at Reliant Energy, recommended integrating load into SCED to support scarcity pricing.
Because offers to shed load would be based on each participating consumer's value of lost load (or opportunity cost), each load's marginal cost of providing energy is equivalent to their current value of lost load, Goff noted, ensuring shortage pricing when warranted.
In terms of particular designs, Goff stressed that payments to load for such demand response should not be the full LMP (as ordered by FERC in the jurisdictional RTOs), especially under an energy-only design, because paying load twice for the same MWs (once through the full LMP and additionally through avoided cost) will inevitably lower offers below their value and possibly lead to uplift. Goff noted that the "Loads in SCED" task force at ERCOT has developed settlement mechanisms that avoid this problem.
Recommendations offered by Calpine include chiefly:
- Eliminate "price taking" MWs below off line NSRS units' Low Sustained Limit (LSL) by setting LSL to zero
- Bid shape requirements for off line NSRS so that ERCOT would have more granular control of the amount of off line NSRS deployed.
Other changes that Calpine said could potentially improve scarcity pricing signals include:
- NSRS Minimum Energy Bid Heat Rate, coupled with a "persistence period" (1 hr., 2 hr., etc.)
- Re-price the market each time NSRS is deployed by backing NSRS MWs out of SCED (in a parallel or ex post manner)
- Re-price the market at the System-Wide Offer Cap each time NSRS is deployed for adequacy purposes (in a parallel or ex post manner)
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