Gas pipeline operators can exchange non-public operational information with PJM and other RTOs under a final rule approved by the Federal Energy Regulatory Commission.
The rule, approved Nov. 15, is the first regulatory change by FERC since it began an inquiry on gas-electric interdependence in February 2012 (AD12-12-000).
The order includes a No-Conduit Rule that prohibits recipients of the information from disclosing it to an affiliate or a third party. The No-Conduit Rule does not affect current communications among pipelines, local distribution companies and gatherers regarding conditions affecting gas flows between them.
In response to comments, the final rule allows transmission operators to seek commission authorization if they wish to share information from an interstate pipeline with a local distribution company.
More than 1,800 people from 200 industry and government organizations, including about two dozen PJM staffers, took part in the North American Electric Reliability Corp.’s two-day cyber and physical security drill Nov. 13-14.
GridEx II tested utilities’ and transmission providers’ crisis response plans through a series of mock cyber and physical attacks, building on lessons learned from NERC’s initial exercise in 2011.
The exercise also tested communications among industry and government agencies through NERC’s Electricity Sector-Information Sharing and Analysis Center (ES-ISAC). The departments of Energy, Homeland Security and Defense participated, along with the FBI and Canadian and Mexican utilities and agencies.
NERC said it will issue a report detailing findings and recommendations from the drill in the first quarter of 2014.
The Federal Energy Regulatory Commission last week gave final approval to Critical Infrastructure Protection (CIP) standards that for the first time cover all bulk power system assets according to their impact on the grid.
Version 5 of the CIP cybersecurity standards replace the current “in or out” designations with a tiered approach which classify assets as high, medium or low impact. (See What You Need To Know About CIP Version 5.)
TOP, IRO Standards Remanded
At the same time, FERC issued a notice of proposed rulemaking that remanded to the North American Electric Reliability Corp. its proposed revisions to reliability standards for system monitoring.
NERC’s Transmission Operations (TOP) and Interconnection Reliability Operations and Coordination (IRO) reliability standards go in the right direction – combining similar requirements, clarifying responsibilities and eliminating redundancies – but go too far, FERC said. Commissioners took pains at their public meeting to strike a friendly tone. “We tried to make sure that the remand tone was such that passions would not be inflamed,” Commissioner Philip Moeller said.
Commissioner Cheryl LaFleur said that the proposed revisions wrongly eliminate transmission operators’ current obligation to monitor and operate within all system operating limits. They would exclude from monitoring, for example, certain system operating limits in one operator’s area that affect another operator’s area. Failing to monitor such limits, FERC said, could contribute to outages.
Language Deleted
Although it approved nearly all the Version 5 CIP standards NERC had proposed, FERC deleted language that it identified as a problem when it proposed approval in April: a provision that required CIP standards to be implemented in a way that “identifies, assesses and corrects” deficiencies. That language would cause inconsistencies and difficulties with enforcement, the commission said. Everyone involved “must have a common understanding of the obligations imposed by reliability standards.” LaFleur said in a statement. “Otherwise, we risk creating gaps in reliability, confusion during audits and a compliance backlog that diverts resources away from improving reliability.”
FERC also told NERC to develop objective criteria for evaluating entities’ cyber protection for low-impact assets.
Although some had objected to creating burdens for assets in the lowest rung of impact, the commission reiterated its position that the standard “does not provide those entities with a clear roadmap of what they need to do.” NERC will not have to draw up a set of specific controls, but could take a number of approaches to fulfill the requirement, FERC said.
Standards Retired
In another reliability action, FERC approved NERC’s proposed retirement of 34 requirements in 19 reliability standards that provide little protection or are redundant of other standards. The order also withdraws 41 outstanding commission directives that NERC modify standards that have been addressed in another way or are too broad.
The Federal Energy Regulatory Commission last week approved a rule sought by the solar industry to streamline interconnections for the growing segment of small generators.
1.1 MW Solar Array at University of Toledo (Plug Smart)
The final Small Generator Interconnection Agreements and Procedures rule (Docket #RM13-2) expands the field of projects eligible for a fast-track process from a 2-MW size limit, but does not adopt the notice of proposed rulemaking’s designation of up to 5 MW for eligibility. Instead, it retains the 2-MW threshold for synchronous and induction machines and expands eligibility for inverter-based machines that meet certain system and generator characteristics.
All projects connecting to lines larger than 69 kV will be ineligible for fast-tracking.
While narrowing the scope of eligible projects, the changes maintain fast-tracking for most distributed solar applications, according to the Solar Energy Industries Association. SEIA, renewables companies and utility associations participated in a stakeholder group that developed the changes on eligibility and other matters.
The rule allows interconnecting customers to ask transmission providers for a pre-application report about system conditions at the point of interconnection. There is a fixed $300 fee for the report but providers can seek higher fees with cost justification. PJM had told FERC that the amount was not enough. PJM also had opposed formalizing the report, saying the RTO already does a lot of pre-application engagement and that a report could create “an inflexible box.”
PJM and others did prevail in arguing for more time -— 20 days instead of 10 — for delivery of that report.
They also won a disclaimer that since the report will require only readily available data at the time of request, it will be non-binding.
FERC also agreed with PJM’s request for more time to provide interconnection agreements, increasing it to 10 days from five, because the fast-track reforms could result in more such agreements.
The rule also accounts explicitly for interconnection of storage devices, and it makes clear that only FERC-jurisdictional systems are subject to the requirements.
Transmission providers will have to submit compliance filings within six months. FERC will allow for regional variations, and will give regional transmission organizations such as PJM more flexibility than transmission providers that are also market participants.
Cheryl LaFleur became acting chair of the Federal Energy Regulatory Commission Sunday, succeeding Jon Wellinghoff, who came under pressure to resign after accepting a law firm position in October.
FERC Commissioner Cheryl LaFleur at PJM Grid 20/20
As a sitting commissioner, LaFleur won’t require Senate confirmation. But she would need congressional clearance if she were to continue in the post after her four-year term ends in June.
Wellinghoff, who is joining the Washington office of Portland-based Stoel Rives LLP, announced his departure at the end of Thursday’s commission meeting. Sen. John Barrasso (R-WY) had criticized Wellinghoff’s plans to remain on the commission until the end of the current session of Congress, even though the chairman said he would recuse himself from cases involving Stoel Rives.
Wellinghoff had remained on the commission after his term expired in July while awaiting Senate confirmation of a successor. Colorado regulator Ron Binz withdrew from contention Oct. 1 in the face of opposition from Senate Republicans and coal interests.
Among those floated as potential nominees to the five-member commission are Arkansas Public Service Commission Chair Colette Honorable, who was elected last week as president of the National Association of Regulatory Utility Commissioners; Norman Bay, director of FERC’s Office of Enforcement; Tennessee Valley Authority board member Lynn Evans, and former Nevada regulator Rose McKinney-James. The commission is currently split between Democrats LaFleur and John Norris and Republicans Philip Moeller and Tony Clark.
Wellinghoff was FERC’s longest-serving chair, appointed in March 2009 after about two years as a commissioner.
A Harvard Law School graduate, LaFleur held numerous positions in New England Electric System and its successor, National Grid USA. She was senior vice president and acting CEO when she retired in 2007.
At FERC, LaFleur has concentrated on reliability and grid security issues. She co-chaired the FERC/NARUC Forum on Reliability and the Environment.
In a statement yesterday, LaFleur noted the commission’s role in ensuring reliability as the generation fleet faces retirements due to environmental regulations. “The Commission also has important work ahead in implementing Order No. 1000, setting transmission rates, and ensuring competitive markets work fairly and effectively for consumers,” she said.
Although she has backed the commission’s major initiatives, LaFleur has not agreed with all decisions. In March, for example, she dissented from an order requiring PJM to allocate the costs of large new transmission lines on a broad “postage-stamp” basis. LaFleur had favored a hybrid approach, combining a localized, “distribution factor” calculation and a broader assessment of benefits for postage-stamp allocation. The effect of that decision is limited to projects PJM had approved before February of this year. The grid operator proposed a hybrid method for projects approved after that time; FERC approved it in March.
ORLANDO — MISO officials last week signaled their opposition to PJM’s new limits on generation imports but said they will be capacity buyers in the near term as they face a shortfall that could result in load shedding as early as 2016.
MISO CEO John Bear said officials hope generation plants being built on Marcellus Shale deposits in Pennsylvania will provide relief as the region copes with a potential 5 to 7 GW capacity shortfall in 2016-17 due to the loss of coal-fired generation.
“We’d like capacity to come in this direction,” Bear told a press briefing on the sidelines of the National Association of Regulatory Utility Commissioners here. “In 16-17 we’ll be capacity challenged.”
MISO is completing analysis of a survey to determine the extent of its shortfall, with results due to be released as soon as next month. MISO officials fear their current 15% reserve margin could be reduced by more than half, even with the anticipated import of 1,000 MW of capacity from the south.
MISO currently meets a 1 event in 10-year loss of load expectation. “You’re going to have more events” in the future, Bear said. “We could go to three events a year.”
Asked about predictions of rolling blackouts, Bear responded, “that’s a little strong.” More likely, officials said, are localized load shed events, similar to what PJM experienced in September.
“You could expect more pinched operating days [forcing operators] into emergency operating procedures,” said General Counsel Steve Kozey.
No `Arbitrary Caps’
Officials said they can’t be certain they’ll be able to tap the new generation in PJM. “They’ve got a lot of retirements, so their flows will change,” Bear said. In an apparent swipe at PJM’s new import limits, he added: “We want flows to be dictated by the physics of the system, not any arbitrary caps.”
PJM stakeholders gave final approval Thursday to new methodology that will limit imports from MISO to 3,000 MW in next year’s base capacity auction. The limits do not apply to pseudo-tied generators that are under PJM control and meet other conditions. (See Members Deadlock on DR in Capacity Auctions)
Richard Doying, MISO executive vice president of operations, said PJM’s methodology for determining cross-border transfer capability is unduly conservative. The methodology dispute was the subject of a hearing before the Federal Energy Regulatory Commission in June. (See FERC Likely to Increase Pressure on PJM-MISO Joint Market Talks.)
The two RTOs are attempting to find agreement on a common methodology as part of their Joint and Common Market initiative. If no agreement is reached, said Bear, “FERC will call balls and strikes. They’ve already done that.”
Interchange Optimization
To optimize real-time interchange energy flows the two regions also are seeking ways to prevent traders from guessing wrong on prices and making uneconomic transactions. PJM stakeholders last month approved creation of a new product, Coordinated Transaction Scheduling, to reduce uneconomic flows with NYISO.
Optimizing flows between MISO and PJM will be more complicated, officials said, because of the higher transaction volume between the two regions.
Entergy Integration
MISO North and South (Source: MISO)
In the short term, MISO officials are focused on completing the integration of “MISO South” — Entergy, Cleco, Lafayette Utilities System, Louisiana Energy and Power Authority, Louisiana Generating and South Mississippi Electric Power Association. Market trials are being conducted now with the cutover scheduled for Dec. 19. The expansion will increase MISO’s peak load from 100,000 MW to 140,000 MW.
MISO lost in the competition for the Western Area Power Administration, Basin Electric and Heartland Consumers Power District, which decided to join the Southwest Power Pool (SPP). “The transmission cost allocation deal with SPP is advantageous to them,” Bear said. “We can’t overcome that.”
Lacking consensus, PJM Thursday dropped plans for a vote on measures to prevent speculation in the capacity auctions, returning the issue to a lower committee.
The Markets and Reliability Committee voted by acclimation to approve PJM’s recommendation to return the issue to the Capacity Senior Task Force.
(Source: Monitoring Analytics)
Because clearing prices in Incremental Auctions (IAs) are usually lower than those in the Base Residual Auction (BRA), participants can profit by selling capacity in the BRA and buying out their commitments in the IAs.
The CSTF voted earlier this month on 11 proposals to remove arbitrage incentives, with PJM’s proposal winning 60% support and the others ranging from 0% to 33%. Two-thirds of voters backed a change in the status quo.
Executive Vice President for Markets Andy Ott said officials hope the delay will allow more members to coalesce around a single proposal, resulting in “less angst” over whether the result will be approved by FERC.
Craig Glazer, vice president for federal government policy, noted that FERC staff raised questions about the issue at a FERC technical conference Nov. 13. Ed Tatum, of Old Dominion Electric Cooperative (ODEC) told the staff at the hearing that one reason for the disparity in prices between the Base and Incremental auctions is that PJM has procured too much capacity in the BRA — imposing excessive costs on load. (See FERC Staff Skeptical on PJM Demand Response Changes.)
Dan Griffiths, director of the Consumer Advocates of PJM States (CAPS), said the MRC would have rejected the staff proposal had it come to a vote. But he was skeptical about the chances of reaching consensus. “I don’t want anyone to think we’re going back to the CSTF to negotiate against ourselves,” he said.
Members spent the first half of yesterday’s CSTF session attempting to narrow their differences on the issue with no apparent breakthrough. Much of the discussion focused on developing penalties — and related credit requirements — tough enough to discourage speculation without creating barriers to entry for small market participants.
Task Force Chair Scott Baker called the delay a “reset … not a reboot,” saying the previous work had provided a “solid foundation” to move forward.
Market Monitor Joe Bowring said the committee needs to develop “clear enforceable rules” to define prohibited speculation. “Right now there’s nothing I can do regarding a participant that I know for a fact is engaging in behavior that we’re concerned about.”
The CSTF has three additional meetings scheduled through January. PJM hopes to win passage of a consensus plan by the end of January in time for a FERC filing in February.
The PJM Board of Managers may seek FERC approval for a plan to change the way demand response clears in capacity auctions despite stakeholders’ rejection of the plan.
That scenario emerged Thursday after a last-ditch compromise to address the RTO’s reliability concerns failed to win members’ endorsement. The proposal by Old Dominion Electric Cooperative won 58% support in a sector-weighted vote by the Members Committee, short of the two-thirds threshold to signal consensus.
After the meeting, Executive Vice President for Markets Andy Ott told RTO Insider that he will recommend the Board seek Federal Energy Regulatory Commission approval of a PJM staff proposal backed by generators. The Board met Friday and is expected to file its plan tomorrow, officials said yesterday.
PJM would be gambling that FERC will find its arguments more persuasive than most members did. The staff proposal, which garnered only 37% support from the Markets and Reliability Committee Nov. 14, did only slightly better at the Members Committee, winning support of nearly 45%.
Other DR, Capacity Initiatives
PJM had more success on a separate proposal that could increase capacity prices as the Members Committee gave final approval to PJM’s methodology for limiting imports.
At the Markets and Reliability Committee meeting earlier Thursday, members also approved a proposal giving PJM more flexibility in the way it dispatches demand response.
Members agreed to postpone an MRC vote on a fourth initiative to prevent arbitrage between the Base and Incremental capacity auctions. PJM officials said they wanted to return the issue to the Capacity Senior Task Force to seek revisions that could win broader stakeholder support. (See Arbitrage Fix Returned to Committee)
Need for Changes in DR
PJM says the volume of limited DR clearing in the capacity market must be reduced because 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.
Officials hope to implement the changes in February, when the RTO will set the parameters for its next Base Residual Auction. Representatives of load and DR providers, who said the PJM plan will increase costs and stunt DR, are certain to file interventions opposing the changes.
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%.
Compromise
ODEC described its proposal as a compromise between the PJM proposal and one submitted jointly by Southern Maryland Electric Cooperative and state public advocates which would reduce the 4.8% by only a portion of the 2.5% holdback.
The SMECO/Advocates proposal had been the most popular with members, falling just short of a two-thirds plurality at the MRC Nov. 14. Its support eroded Thursday, when it won only 54% support from the Members Committee.
Susan Bruce, representing the PJM Industrial Customer Coalition, said her group voted to support the ODEC proposal in an effort to craft a compromise. “This is certainly not our litigation position … at FERC,” she said.
Raghu Sudhakara, of Rockland Electric Co., said the ODEC proposal was less costly than PJM’s and “very close” to the PJM plan on reliability.
But ODEC’s plan was opposed by PJM as well as most generators and transmission owners. Stu Bresler, vice president of market operations, said the ODEC proposal might not hurt reliability in the short term but would in the long term by undercutting prices in the capacity auctions.
Jason Barker, of Exelon, said the plan could increase Installed Reserve Margins, ultimately costing customers more. “This is a bad proposal,” Barker said. “As a transmission owner and a generator operator we’re not satisfied with being `very close’ on reliability.”
Market Monitor Joe Bowring also panned the ODEC proposal, saying PJM’s plan was already a compromise from what he believes the RTO should do: eliminating limited DR altogether. Bowring said limited DR is suppressing the capacity market by $3 billion to $4 billion annually.
ODEC’s Ed Tatum said PJM was using “circular logic” in arguing that increased capacity costs under the RTO’s proposal will be counterbalanced by reduced energy prices. The purpose of the capacity market, he noted, is to solve the “missing money” problem — the fact that generators don’t earn enough in energy market revenues to cover their costs.
Late Change to Capacity Limit
The lid on external generation resources would limit imports in next year’s base capacity auction to 6,200 MW, a 17% drop from the volume that cleared in May’s auction. (See Members OK Capacity Import Limit; Prices May Rise.)
The Members Committee approved it with 85% support after a last-minute revision to eliminate a provision related to the requirements for external generators seeking an exemption from the cap.
As amended, the exemption will apply to external generators with firm transmission that commit to providing capacity in future auctions and have pseudo-ties allowing PJM to control their dispatch.
Deleted was a requirement that the generator be dedicated to an identified load in PJM. PJM officials said that the provision was discriminatory because it is not required of internal capacity resources. Bresler said it was also unnecessary because of the “must-offer” requirement.
Several members expressed unhappiness that the issue — which could have led FERC to reject the proposal — hadn’t been flagged earlier by PJM. Bresler said PJM officials learned of the issue several days earlier.
“I’m surprised and disappointed to have this change at the last minute,” said Reem Fahey, of Edison Mission. “I believe it makes the proposal a lot weaker.”
Dynegy’s Jason Cox, however, said PJM had to make the change. “This is one point we will happily protest if it ends up in a FERC filing,” he said.
Slower Transition Rejected
PJM’s initiative to increase the diversity of DR resources won 67.4% support of the MRC in a sector-weighted vote, just enough to clear the two-thirds threshold.
Because it passed the two-thirds hurdle, the committee did not vote on a proposed amendment by David “Scarp” Scarpignato, of Direct Energy, to slow the transition to quicker dispatch requirements.
Current rules require PJM operators to provide two hours’ notice before dispatching DR. Under the new rules, resources will be dispatchable in 30 minutes beginning delivery year 2015/16 unless they can demonstrate physical reasons for a longer dispatch. Curtailment Service Providers will be able to choose among 30-, 60- and 120-minute dispatch for DY 2014/15.
Scarp asked for a slower transition that would impose a 60-minute default in DR 2015/16 and delay the 30-minute requirement until DR 2016/17.
Marji Philips, also of Direct Energy, said a slower transition would avoid having to make changes in the middle of current contracts with customers. “Our contracts allow us to `reg out’ [change terms because of regulatory requirements] but that’s not how we like to work with customers,” she said.
PJM officials opposed the change, saying their proposal already represented a compromise from their preference to implement the 30-minute requirement next year. “We continue to over-call DR and allocate those costs to the members,” Bresler said.
Ott said PJM is concerned about having the flexibility by summer 2015 to address coming generation retirements.
Pepco, Maryland PSC Mollified
Representatives of Pepco Holdings Inc. and the Maryland Public Service Commission, who had earlier expressed concern about the impact of the changes on their “mass market” DR programs for residential and small commercial customers, said they were satisfied that the rules will provide them needed flexibility.
“PJM was very responsive,” said the PSC’s Walter Hall. “We do think we’ve come to a meeting of the minds.”
ORLANDO — Flat load growth and new technologies are challenges but not mortal threats to utilities, NARUC panelists said last week.
Jim Hempstead, Moody’s
Citing utilities’ political clout and outsized role in regional economies, Hempstead said: “We think before it becomes an intractable problem it will be dealt with in some way.”
New rate designs were among the solutions proposed in sessions on the challenges posed to current utility ratemaking and business models.
New Regulatory Models
“There’s no doubt that the regulatory model has to change,” Alan James, chairman of Macquarie Capital’s energy infrastructure group — owner of Duquesne Light Co. — told regulators. “I would ask you to look across the stakeholder groups and not just be focused on the customer.”
Maryland People’s Counsel Paula Carmody
Trackers — direct pass-throughs of costs to customers — are popular with utilities and a “positive” for credit ratings, said Hempstead.
But they face resistance from stakeholders such as Maryland People’s Counsel Paula Carmody, who pronounced herself “not a fan of trackers or forecasted rates.”
Former PSEG executive Anne Hoskins, appointed to the Maryland Public Service Commission in August, said she’d like to find ways to align regulators’ goals with the incentives of utility executives. “What are the metrics that they will respond to in compensation agreements?” she asked.
More Nimble
Other speakers said utilities must become more nimble and capitalize — rather than being victimized by — new technology.
“Allow utilities to invest in these disruptive technologies and they will indeed do so,” said Julien Dumoulin-Smith, a director in UBS Investment Research’s Utilities group.
James and Hempstead said that utilities should embrace commercial-scale solar power, until now the domain of independent developers.
Massachusetts Commissioner David Cash cited a “huge underinvestment” in research and development by utilities compared to similar size companies. “What is the energy app that customers are going to want?” he asked.
Bundling electricity with home security and other services”sounds very compelling to a consumer,” responded Carol Choi, vice president of integrated planning and environmental affairs for Southern California Edison. “But it’s much more challenging to achieve.”
Maryland Commissioner Kelly Speakes-Backman said innovation is difficult for utilities because regulators are risk-averse. “Regulators don’t like unknowns. The way to avoid that is not to allow it.”
Divergent Views
Maryland Public Service Commissioner Anne Hoskins
James predicted utility share prices will come under pressure as the economy improves and investors move away from “defensive” investments.
Other speakers said they saw reason for optimism.
“Zero load growth is a challenge,” acknowledged Choi. “You like to see people using your product.” But she said the electrification of transportation offers growth prospects.
“Resiliency investments are an upside area for utilities if they get it right,” said Dan Bakal, of CERES, a non-profit organization that advocates “sustainability leadership.”
Moody’s Hempstead said utilities are benefiting from reductions in regulatory lag, increases in trackers and improvements in “regulatory tone.” “We’ve got almost the entire industry on review for an upgrade,” he said.
PJM May Seek FERC OK Despite Stakeholder Opposition
The PJM Board of Managers may seek FERC approval for a plan to change the way demand response clears in capacity auctions despite stakeholders’ rejection of the plan.
That scenario emerged yesterday after a last-ditch compromise to address the RTO’s reliability concerns failed to win members’ endorsement. The proposal by Old Dominion Electric Cooperative won 58% support in a sector-weighted vote by the Members Committee, short of the two-thirds threshold to signal consensus.
After the vote, Executive Vice President for Markets Andy Ott told RTO Insider that he will recommend the Board seek Federal Energy Regulatory Commission approval of a PJM staff proposal backed by generators.
A Gamble
PJM would be gambling that FERC will find its arguments more persuasive than most members did. The staff proposal, which garnered only 37% support from the Markets and Reliability Committee Nov. 14, did only slightly better at the Members Committee yesterday, winning support of nearly 45%.
PJM says the changes are needed because 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.
Ott said he expects PJM to file its proposal with FERC before Thanksgiving in the hope of implementing the changes in February, when the RTO will set the parameters for its next Base Residual Auction. Representatives of load and DR providers, who said the PJM plan will increase costs and stunt DR, are certain to file interventions opposing the changes.
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%.
Compromise
ODEC described its proposal as a compromise between the PJM proposal and one submitted jointly by Southern Maryland Electric Cooperative and state public advocates which would reduce the 4.8% by only a portion of the 2.5% holdback.
The SMECO/Advocates proposal had been the most popular with members, falling just short of a two-thirds plurality at the MRC Nov. 14. Its support eroded Thursday, when it won only 54% support from the Members Committee.
The ODEC plan was opposed by generators, transmission owners and PJM. Stu Bresler, vice president of market operations, said the ODEC proposal might not hurt reliability in the short term but would in the long term by undercutting prices in the capacity auctions.
Market Monitor Joe Bowring also panned the ODEC plan, saying PJM’s proposal was already a compromise from what he believes the RTO should do: eliminating limited DR altogether. Bowring said limited DR is suppressing the capacity market by $3 billion to $4 billion annually.
Other DR, Capacity Initiatives
PJM had more success on a separate proposal that could increase capacity prices as the Members Committee gave final approval to PJM’s methodology for limiting imports. The proposal was approved by 85% of stakeholders.
At the Markets and Reliability Committee meeting earlier Thursday, members also approved a proposal giving PJM more flexibility in the way it dispatches demand response. The plan won 67.4% support in a sector-weighted vote, just enough to clear the two-thirds threshold.
Members agreed to postpone an MRC vote on a fourth initiative to prevent arbitrage between the Base and Incremental capacity auctions. PJM officials said they wanted to return the issue to the Capacity Senior Task Force to seek revisions that could win broader stakeholder support.
The CSTF voted earlier this month on 11 proposals on the arbitrage issue, with PJM’s proposal winning 60% support and the others ranging from 0% to 33%. Two-thirds of voters backed a change in the status quo.
RTO Insider will have an updated report on the capacity market and demand response initiatives — plus other action from the Members and Markets and Reliability committees and highlights from the National Association of Regulatory Utility Commissioners (NARUC) annual meeting in Orlando — in Tuesday’s newsletter.
