FERC Rejects Arbitrage Fix; OKs Most of DR Changes

By Rich Heidorn Jr. and Ted Caddell

PJM yesterday opened the 2017/2018 Base Residual Auction amid modest hopes among generators that the RTO’s rule changes will cause a rebound in prices.

Last year’s capacity auction saw big price drops in most of PJM, compounding the woes of generators, whose energy revenues have been suppressed by cheap shale gas.

PJM stakeholders approved several major changes in an attempt to bolster the capacity market, including a cap on imports and limits on demand response. But lackluster load growth and auction parameters that suggest there may be less price separation this year than last have tempered expectations.

Late Friday, the Federal Energy Regulatory Commission approved most of PJM’s proposal for making demand response an “operational resource.” However, the commission rejected a proposal requiring DR providers to respond to sub-zonal dispatch. The commission also rejected PJM’s proposals for eliminating financial speculation in the auction, instead scheduling a technical conference to develop a solution. (See related story, PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)

2013 Results

In last year’s auction, RTO prices dropped 56% to $59.37/MW-day, while prices in ATSI dropped more than two-thirds (to $114/MW-day) and MAAC fell 29% ($119). Prices in the Public Service zone rose 31% to $219.

Generation imports nearly doubled, leading some to question their deliverability. (See Capacity Auction: New Generation, Imports Up, Prices, DR Down.)

Over the objections of consumer advocates and others, FERC approved PJM’s plan to create five import zones with a combined limit of 6,499 MW for this year’s base auction (ER14-503). (See FERC Clears Capacity Import Limits.)

The cap represents a 17% reduction from the imports that cleared in 2013. However, external resources can win an exception to the limits if they are pseudo-tied; have confirmed, firm long-term transmission service; and accept the same must-offer requirement as internal resources. PJM’s planning parameters show that only 1,524 MW of the 6,499 MW are available after 4,777 MW in exceptions.

FERC also approved rules requiring DR providers to give more assurances in their offers (ER13-2108), as well as limits on the clearing of limited demand response (ER14-504) that a PJM simulation suggested could increase capacity revenues by $1 billion annually. (See FERC OKs Limits on DR in Capacity Auction.)

Utility Execs Not Excited

In earnings calls over the last two weeks, executives of PJM companies praised the RTO’s rule changes but said they didn’t expect a dramatic rise in prices.

AEP CEO Nick Akins predicted RTO prices of $80 to $100 but added, “But who knows? I mean … the way this capacity construct works … things happen all the time.” Akins’ prediction is in line with that from UBS Securities, which predicted in February that RTO prices will rebound to $80 with MAAC flat at $120.

FirstEnergy CEO Tony Alexander told analysts he was encouraged by these “modest reforms” but more excited that “momentum is growing for changes that can truly help” such as a premium for having fuel on-site, which could boost nuclear and coal plants.

“I don’t think any of the rules currently approved are going to move the auction substantially,” added Leila L. Vespoli, FirstEnergy’s executive vice president of markets.

FirstEnergy President Donald R. Schneider said the “wildcard” will be the volume of offers from new generation in the interconnection queue.

PSEG CEO Ralph Izzo, however, said it is the actions of DR providers that may have more impact. “Really, a large part of the auction turns on what you expect for DR,” he said. The volume of cleared DR dropped 16% last year over 2012.

PPL CEO William Spence said there are too many variables to make a prediction on prices.

“There are a lot of moving parts, a lot of modifications have been made. There is a lot of kind of noise out there around the residual auctions and so forth,” he said. “So I think for this year at least, we are not going to put out an expectation around where we expect RPM prices to settle out, because there is a lot more uncertainty, in our view, coming into this auction than we have seen in past auctions.”

Spence said neither the auction results nor the spike in energy prices over the winter would influence the company’s long-term strategy. The company is reportedly considering selling its generation assets.

“We continue to have, as our No. 1 priority, the aggressive cost control and optimizing the dispatch of our plants,” he said. “At the same time, we do continue to consider other options that could enhance value. There is no particular data point or viewpoint of forward prices that we are waiting for or that would substantially impact our thought process around strategic options for that business.”

IPP Views

Among independent power producers, Calpine was downbeat while NRG was more positive.

Calpine President and Chief Operating Officer John B. Hill said the company has a “flattish to the modestly down view” of this year’s auction prices. “PJM has pushed forward some very strong rules … but we don’t have super high expectations for the auction this year,” he said.

NRG Energy’s Chief Operating Officer Mauricio Gutierrez was a bit more optimistic. “The combined effect of higher requirements and limits on demand response, the limits on capacity imports and the significant levels of un-cleared coal megawatts are positive signs in PJM,” he said.

Load Forecasts

PJM’s load forecast, released in February, predicts the RTO’s summer peak growing almost 7,000 MW to 164,195 in 2017, a 4.4% increase.

PJM predicted growth of 80 to 120 MW in APS from hydraulic fracturing and a 288- to 896-MW boost in the Dominion zone from new data centers. An undisclosed project under construction is forecast to add 50 to 195 MW to BGE’s summer peak beginning in 2017. Peak demand in the AEP zone was reduced by 370 MW, reflecting the loss of an aluminum smelter.

CETO/CETL ratios

PJM’s planning parameters report noted that planners had added three Locational Deliverability Areas (LDAs) — ComEd, BGE and PPL — to the nine modeled in last year’s auction.

Prior to each BRA, the Capacity Emergency Transfer Objective (CETO) and Capacity Emergency Transfer Limit (CETL) are calculated for each of 27 potential LDAs to determine whether separate demand curves should be modeled for them to ensure reliability.

The MAAC, EMAAC and SWMAAC LDAs are always modeled separately.

LDAs are also modeled separately if the CETL is less than 1.15 times its CETO or the LDA had a locational price adder in any of the three prior base auctions.

PJM can also model LDAs separately if it believes it necessary for reliability.

PJM said it would model the ComEd, BGE and PPL LDAs separately for the first time because of concern over generation retirements. The RTO said it wanted to “proactively identify locational supply concerns before they actually occur.”

PJM said most CETL values are about equal to or slightly higher than last year’s auction. The exception is the Pepco LDA which dropped to 5,208 MW, a reduction of 22% from last year, due to generator retirements.

The PS, DPL and SWMAAC zones showed the lowest CETO/CETL ratios, all below 1.4.