Billions are at stake. Vertical demand curves are bad. On that there was agreement at last week’s Markets and Reliability Committee meeting.

Beyond that, however, there was little common ground evident in a first reading of PJM’s proposal to cap the volume of Limited Demand Response that can clear in the capacity auction.

PJM’s proposal came to the MRC after winning support of 75% of the voters at the Capacity Senior Task Force. None of three alternatives proposed by states and demand response aggregators won support of more than a quarter of the 182 voters.

Katie Guerry, representing DR aggregator EnerNOC, which proposed one of the alternatives, said she would continue to seek work a consensus before the MRC votes on the issue next month. Some members suggested PJM merge its proposal with “Option B,” proposed by state consumer advocates and Southern Maryland Electric Cooperative (SMECO).

But there was no indication that PJM and the generation owners who strongly back the RTO proposal were willing to give any ground. If PJM is unable to obtain support of two-thirds of stakeholders in a sector-weighted vote of the MRC, the PJM Board of Managers can unilaterally decide to file the proposed changes with the Federal Energy Regulatory Commission.

“Option B just doesn’t do it,” said Andy Ott, PJM executive vice president for markets. “It won’t address the reliability problems we’ve identified.”

Boom-Bust Cycle

PJM says the current rules result in a vertical demand curve that leads to boom-bust cycles in which the system “oscillates” between being long on capacity, with low prices, and being short on capacity with high prices.

PJM wants the new rules in place by February, when the RTO must post planning parameters for the 2014 Base Residual Auction.

Under current rules, 4.8% of PJM’s reliability requirement can be filled with limited demand response, with higher levels possible if excess capacity clears against the sloped Variable Resource Requirement (VRR) demand curve. PJM wants to reduce the 4.8% by all of the 2.5% Short-term Resource Procurement Target (STRPT) for a net of 2.3%.

The SMECO/Public Advocates proposal would reduce the 4.8% by only a portion — to be determined — of the 2.5% holdback.

A simulation found that PJM’s proposal would have increased total costs by $1 billion over actual costs in the 2015/16 auction and $800 million for 2016/17 while reducing the volume of limited DR clearing in the two years by 64%.

The SMECO/Public Advocates’ proposal would have increased costs by less than 1% over the two years while reducing the volume of limited DR by about one-fifth. (See Demand Response Changes Could Cost $1B Annually)

Cheaper Long-Term Solution

PJM officials said their proposal will ultimately save consumers money by ensuring adequate capacity and keeping energy market prices low.

The one-year snapshot provided by the simulation “is not looking at the big picture,” Ott said. “What we’re looking at is the long term low-cost solution.”

Ott said the projected increase in capacity costs “could be looked at as what we’re undervaluing long-term resource adequacy at today.”

Without reforms, Ott said, “we’re going to have a much bigger reliability problem that will be much more expensive to correct because there will be less time.”

CEO Terry Boston, who speaks infrequently at meetings, also weighed in, noting that energy market costs were the lowest in 10 years in 2012. “That’s because we’ve had adequate capacity to call on when we need it,” he said. Through September, load-weighted energy represented almost 78% of costs versus 13% for capacity.

Representatives of Exelon, Duke and AEP strongly backed PJM’s proposal.

Duke’s Ken Jennings said PJM’s baseload coal plants, which clear in the energy market at $40/MWh or less, “will go away” without changes to allow an increase in capacity prices.

Difficult `Value Proposition’

But those representing load were not convinced of the urgency for changes and said PJM’s proposal could damage the growth of demand response.

“We’re struggling to see it in the same way as PJM,” said Susan Bruce, representing the PJM Industrial Customers Coalition. Paying an additional $1 billion annually for capacity, she said, is “a value proposition that’s hard for us to get our hands around.”

“If there’s other, better, data [to counter the simulation estimates] we’d like to see it,” said Walter Hall, of the Maryland Public Service Commission.

Hall said the state has not taken a final position on the issue but is concerned that the capacity market limits and other changes proposed by PJM to allow more flexible deployment of DR threaten the state’s EmPOWER Maryland load-reduction programs, which were authorized by the state legislature.

“We want to see [DR] maximized,” Hall said.

DR gets the vast majority of its revenue from the capacity market. “Without those revenues the programs might not be able to continue and certainly wouldn’t be able to grow,” Hall said.

BGE, Pepco Impact

Baltimore Gas and Electric and Pepco Holdings Inc. have told state regulators that PJM’s proposals to dispatch DR by zip code and with as little as 30 minutes lead time won’t work with residential and small business participants, Hall said.

He said the state would consider “taking this up with FERC if necessary” to prevent restrictions on the program.

Gloria Godson, representing PHI, echoed Hall’s concerns. “We’re going to have significant customer confusion and customer education issues at a minimum,” she said.

Unlike PHI, which has divested its generation, BGE parent Exelon Corp., which owns more than 23,000 MW of generating capacity in PJM, stands to benefit from increases in capacity prices.

Jason Barker, representing Exelon, said reliability is the paramount issue in the current debate. “We shouldn’t lose sight of that in light of the economic interests,” he said. “BGE supports PJM’s proposals on the basis of reliability, comparability and market efficiency,” he added.

Ed Tatum, representing Old Dominion Electric Cooperative, said he agrees with PJM that there must be caps on limited DR. But he said PJM’s proposal “appears to go beyond what is really necessary.”

Eliminating the 2.5% “holdback” will cut the volume of limited DR clearing by half, he said. “That’s a major change … and a big transfer of wealth.”

He urged PJM to modify its proposal to find consensus with representatives of load — to “see if there isn’t something that we as a family can live with.”

‘Fabricated’ Emergency

The sharpest exchange of the more than hour-long debate came when Duke’s Jennings criticized the deployment of demand response, which set prices at $1,800 per MWh in some zones during heat waves in July and September.

Such deployments should be limited to “real emergencies,” he said, “not fabricated emergencies that arise because we decided to drive … generators out of the market.”

Guerry said Jenning’s comment was a “horrible misrepresentation of what happened in September.

“It wasn’t a fabricated emergency. [DR] was the last resource available in the dispatch stack before having to go to load shedding,” she said.

Others in the room shook their heads in disagreement with Guerry’s account. Although PJM did implement limited load shedding in the September event due to local reliability concerns, officials said they had generation in reserve that could have been called upon during the two heat waves. Guerry said later that she was referring specifically to PJM’s dispatch of DR in the ATSI region on Sept. 10 and 11, when it set prices at $1,800/MWh for several hours.

Guerry questioned the foundations of PJM’s proposal. “We continue to have questions about whether the vertical demand curve has been reintroduced,” she said.

She reiterated her call for a delay on the capacity market revisions pending other changes to increase the flexibility of DR. “We’re very concerned that we’re developing limits on a product that we have not finished … redefining,” she said.

Stakeholders will continue the debate at tomorrow’s CSTF meeting.