As expected, the PJM Board of Managers asked the Federal Energy Regulatory Commission to approve capacity market changes rejected by stakeholders last month.
PJM’s Nov. 29 filing (ER14-504) seeks to change the way demand response clears in capacity auctions. It would resurrect a PJM proposal that won only 45% support from the Members Committee Nov. 21 and 37% from the Markets and Reliability Committee Nov. 14.
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 threatens reliability.
The RTO said it erred in 2011 when it won FERC approval for rules incorporating limited and extended summer demand response into the capacity market. The rules include measures for determining the maximum amount of the limited products that could clear the auction without hurting reliability.
“However, instead of using those `Reliability Targets’ as caps on the more-limited Demand Resources, PJM subtracted those values from the overall capacity requirement, and set the resulting value as a floor on the less-limited capacity product,” PJM said. “This one subtle distinction in the 2011 Demand Resource product rules, it turns out, has far-reaching adverse effects.”
Currently, 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%.
A simulation by PJM found that the RTO’s proposed changes would have increased total capacity costs by nearly $2 billion over the last two Base Residual Auctions. (See Demand Response Changes Could Cost $1B Annually.)
PJM said that because its proposal was unable to win supermajority support from stakeholders the board used its authority to submit the changes independently under section 205 of the Federal Power Act. “These RPM market reforms are concerned with preserving the reliability of the PJM Region, which is a core responsibility of the PJM Board,” PJM wrote.
Officials hope to implement the changes in February, when the RTO will set the parameters for its next base auction.
As of yesterday, 10 parties had filed notices to intervene in the case, including regulators from New Jersey, Delaware, Maryland, Ohio, Pennsylvania and the District of Columbia and the Organization of PJM States Inc. Also filing were the Market Monitor, Achieving Equilibrium LLC, and the PJM Power Providers Group.
Advanced electric storage devices should be treated like limited demand response resources in the capacity market because of their short run times, PJM says.
PJM envisions rating advanced storage devices for six or 10 hours of output, PJM’s Tom Falin said in a presentation Wednesday to a Planning Committee panel developing rules for the technology. That makes them similar to limited DR, which cannot be dispatched for longer than six hours at a time.
1.2 MW fuel cell at a food processing plant (Source: FuelCell Energy Inc.)
As such, the devices may receive lower prices in capacity auctions than less limited products.
Falin said treating storage similar to DR was preferable to another approach PJM considered, a Loss of Load Expectation (LOLE) analysis. Falin cautioned that his comments did not reflect an official PJM position but “some ideas we’ve kicked around.”
PJM members agreed in September to develop rules for allowing storage devices — now generally limited to frequency regulation — to offer into the capacity auctions. (See PJM to Consider Storage as Capacity.)
Under the scenario Falin outlined, storage resources such as batteries or flywheels would be designated as either six- or 10-hour storage devices. For example, a 60 MWh resource could be rated as a 10 MW, 6-hour resource or a 6 MW, 10-hour resource.
Multiple resources of similar design and capacity could be aggregated if they were located on the same bus.
The resource’s unforced capacity (UCAP) value would be determined by the capacity value less an unavailability rate. Resources lacking an operating history would be required to perform a summer and winter capability test.
Also Wednesday, Tom Rutigliano, of Achieving Equilibrium LLC and Janette Dudley of Demansys Energy, briefed the committee on their own proposal for incorporating storage into the Reliability Pricing Model.
They said PJM should use existing rules for generation with as little modification as possible. They would require storage to offer into the day-ahead energy market.
Units that run out of energy would take a forced outage. “Immature units” that have not established forced outage rates, would use average rates for the class of technology involved.
Falin said he will be working with PJM Operations and Markets staff to define dispatch and capacity market rules and energy bidding requirements. The rules will be incorporated in Manual 21: Rules and Procedures for Determination of Generating Capability.
At least 29 major companies are incorporating a carbon price into their long-range planning, according to a report from the environmental data company CDP. “It’s climate change as a line item,” said CDP North America President Tom Carnac. Among the companies identified are American Electric Power and Duke Energy as well as oil majors such as ExxonMobil.
Customers of rural electric cooperatives can apply next year for federal loans to make energy efficiency improvements. The Agriculture Department’s Rural Utilities Service previously made loans only to cooperatives for infrastructure projects. Under a policy change, the service will make $250 million in funding available for customer projects in 2014.
President Barack Obama ordered the federal government to obtain 20% of its electricity from renewable sources by 2020, nearly triple the current 7.5% goal. The American Coalition for Clean Coal Electricity said the order was impractical and would raise electricity costs.
In a decision sought by the wind power industry, the Obama administration issued rules that allow wind-power companies to get permits to kill and harm bald and golden eagles for up to 30 years. Environmentalists oppose the rule as “a blank check” for the so-called takings and said they would challenge it.
All the carbon emission reductions from closing coal plants may be canceled out by the large amount of new industrial activity fueled by natural gas, according to a report from the Environmental Integrity Project. The organization says the Environmental Protection Agency should regulate industrial greenhouse gas sources.
Ontario-based Algonquin Power is buying the remaining 40% of a 400-MW U.S. wind power portfolio from Gamesa Wind US for about $117 million. Algonquin already holds 60% of the three projects, which include Minonk in Illinois, Sandy Ridge in Pennsylvania and Senate in Texas.
Dominion promoted executives to head two business units, effective Jan. 1. Robert M. Blue, now a vice president, will become president of Dominion Virginia Power and Diane Leopold, vice president at Dominion Transmission, will become president of Dominion Energy. Among other changes, Dominion also named P. Rodney Blevins to senior vice president and chief information officer and Katheryn B. Curtis to senior vice president for power generation.
Duke Energy renamed its Cliffside Steam Station after former President and CEO Jim Rogers, who will retire as board chairman this month. The 1,375-MW James E. Rogers Energy Complex comprises two coal units. Because of Rogers’ efforts, 825-MW Unit 6 is “one of the cleanest, most efficient coal units in the world,” the company said.
The Nuclear Regulatory Commission is reviewing Duke Energy’s safety plans at the shuttered Crystal River plant due to concerns over a possible strike by the plant’s unionized workers. Duke’s contract with 1,800 members of the International Brotherhood of Electrical Workers expired last week. The IBEW represents operations, maintenance, chemistry, radiation protection and warehouse personnel.
Houston-based Dynegy closed on its purchase of five Illinois coal plants from Ameren, which is focusing more on its regulated businesses. The closing came about two weeks after Dynegy got a five-year pollution control waiver from the Illinois Pollution Control Board for the Ameren plants. The deal had hinged on that waiver.
PJM generators told the Federal Energy Regulatory Commission last week that it should go beyond PJM’s qualification rules for demand response providers — with some proposing that planned DR resources be banned from the capacity market altogether.
Seven generators and two generator trade groups filed comments last week following a FERC technical conference Nov. 13 on PJM’s proposal to require “Sell Offer Plans” certified by the DR company officers and resource-specific data in some zones. Only a single Curtailment Service Provider, Comverge Inc., submitted comments opposing the rules, filed by PJM Aug. 2.
Support from Market Monitor
The generators — Calpine, Exelon, PSEG and four Ohio utilities — said the overwhelming stakeholder support for the proposed rules and the silence of most DR providers means the changes are reasonable and should be approved.
PSEG, the PJM Power Providers trade group and the Ohio utilities — FirstEnergy, AEP, Dayton Power & Light and Duke-Ohio — went further, saying FERC should order PJM to take tougher action against DR than the RTO could get through the stakeholder consensus process.
The failure to do so will allow speculative DR offers to continue suppressing capacity market prices and threatening reliability, they said. “The issue here is not `existing generation versus DR’ as some may seek to cast it,” the Ohio utilities wrote. “The issue is real versus speculative capacity resources.”
The generators have an ally on this issue in the Market Monitor, which called the PJM proposal a “compromise that does not solve the issue and which will lead inevitably to the need for further changes.”
Rules Vague
Comverge insisted in its filing that PJM’s rules are vague and unnecessary and will depress DR’s growth, echoing comments the company’s vice president of regulatory and market strategy, Frank Lacey, made at the hearing.
“PJM has neglected to provide any objective substantive criteria upon which it will determine the adequacy of DR Sell Offer Plans,” the company wrote. Allowing PJM “complete discretion” in accepting or rejecting the DR Sell Offer Plans violates the Federal Power Act’s prior notice requirements, the company said.
Ohio Utilities’ Filing
FirstEnergy and Duke protested the PJM proposal as insufficiently tough in a joint filing in August. For the post-conference comments, the two companies teamed up with DPL and AEP with a joint filing that cited analyses by a former FERC economist and a former PJM manager.
Former PJM transmission planning manager Scott Gass said in an affidavit that the RTO needs resource-specific information to identify locational delivery areas, which are priced as separate regions in the base auction. Gass performed an analysis of the ATSI transmission zone that he said shows that a reliability event that could be solved with 400 MW of targeted DR would require twice as much if the resources’ precise location cannot be identified.
The utilities also filed an affidavit from former FERC economist David Hunger, who analyzed the impact of “non-physical” DR offers on capacity prices. Because of the steepness of the demand curve, Hunger said, “a relatively small increase in the supply due to non-physical supply offers can result in a very large drop in the RPM clearing price.”
PJM’s Proposed Changes
The proposed Tariff changes require that officers of CSPs certify that they have a “reasonable expectation” of delivering the demand resources offered into the base Residual Auction. Comverge said the officer certifications are vague and give PJM too much discretion in enforcement.
The rules also set conditions under which PJM will flag transmission zones in which CSPs are claiming high levels of DR. CSPs offering resources from those zones will have to provide detailed site-specific information.
Comverge said the requirement creates a barrier to entry and is not motivated by reliability concerns. “Clearly, PJM is not basing its tariff changes on reliability concerns, because the changes proposed do not involve any sort of reliability analysis; they just say `X% of Demand Response is too much,’” Comverge said.
Generators have their own complaints about the criteria for flagging zones, saying they are too lenient.
Additional Changes Sought by Generators
The Ohio utilities said the commission should require DR to offer into the day-ahead energy market as is required of generators. The lack of such a requirement obscures the cost of energy in high demand periods, resulting in higher overall production costs and uneconomic dispatch of DR, the utilities said. A must-offer obligation would allow PJM operators to dispatch DR economically rather than as a block.
PSEG said PJM should require customer-specific information for all DR, not just those in flagged zones. The company also said PJM should either “tighten up the proposed DR Sell Offer Plan requirements” or be ordered to “enforce the Tariff provisions that already exist – which would require a contract between the CSP and its customers for the committed load reduction prior to the BRA.”
The Tariff requires that a “Capacity Market Seller may submit a Sell Offer for a Capacity Resource in a Base Residual or Incremental Auction only if such seller owns or has the contractual authority to control the output or load reduction capability of such resource.”
The PJM Power Providers, an organization representing more than a dozen generators and headed by the former chairs of the Pennsylvania and Michigan utility commissions, told FERC that the changes are needed but that “there is more work to be done” and questioned whether PJM should reevaluate “the participation of Planned DR in RPM.”
Market Monitor: Enforce Current Rules
The Market Monitor said PJM has not properly enforced its rules requiring that Planned DR must be a specific, physical resource. “This rule requires identification of a specific customer and a specific site, but does not require a contract,” the Monitor wrote.
“Under the current application of the rules, DR providers may not have identified Planned DR customers, may not have clear plans for implementing DR measures for these customers, and may not receive commitments from new customers until relatively close to the delivery year and well after the RPM BRA is run for that delivery year.
“PJM’s approach would not address the problem as well as the preferred option to enforce the existing rules and modify the existing rules to make explicit the obligation of cleared BRA resources to provide physical resources in the delivery year.”
What Will FERC Do?
The commission will weigh PJM’s filing against Congress’ direction in the 2005 Energy Policy Act that “unnecessary barriers to demand response participation in energy, capacity and ancillary service markets shall be eliminated.”
In ordering the technical conference, the commission said the proposed changes had not been proven just and reasonable and might be discriminatory. FERC staff expressed similar skepticism at the technical conference.
But Republican Commissioners Philip Moeller and Tony Clark have indicated they are leaning in support of PJM’s changes and Comverge’s arguments lacked the amplification the multiple generators provided in PJM’s support.
Comverge’s argument that the requirements are onerous could be undercut by the fact that PJM found “nearly all DR Providers” that offered into the 2013 BRA submitted adequate Sell Offer plans.
The rules will automatically take effect unless FERC rules by March 2 with an order modifying them. Another option is that the commission could delay a ruling in order to evaluate them along with other DR changes making their way through the stakeholder process. (See Members Deadlock on DR in Capacity Auctions.)
No one spoke up when Market Monitor Joe Bowring opened the floor to stakeholders in the Monitor’s annual Advisory Committee meeting Friday.
No matter. Bowring and his staff took the opportunity to renew their case for eliminating “sham scheduling” and changing PJM rules on opportunity costs.
Opportunity Costs
The Monitor told the more than 20 members and PJM staffers who attended that he will seek Federal Energy Regulatory Commission approval for changes to the opportunity cost calculations because stakeholders have been unable to agree on a solution.
The Monitor says current methods of calculating opportunity costs for some markets and services are “inconsistent and inaccurate” and that there are no Tariff definitions for costs for black start units, reactive services and synchronous condensing.
Bowring said he plans to file proposed changes with FERC next year but is “very much open to discussion” with stakeholders beforehand.
‘Sham Scheduling’
Bowring also reiterated his call for an end to so-called “sham scheduling.” The Market Implementation Committee agreed in April to investigate the Monitor’s concern but the issue hasn’t surfaced since then. (See MIC to Probe “Sham Scheduling”) The MIC’s 2014 work plan shows the issue scheduled for discussion beginning next month.
PJM prices transactions with external balancing authorities based on the source and sink identified on the NERC eTag.
The Monitor said some traders could be manipulating PJM’s interface pricing points by breaking schedules into multiple “back-to-back” transactions that hide the actual source of generation.
Monitoring Analytics’ John Dadourian gave an example of a New York-to-PJM transaction that should result in a settlement of $16. Done by separate transactions through the other regions, the total settlement involved would be $37, Dadourian said.
In another example, a trade from Ontario to MISO, which should result in a net settlement of $5, instead totals $20 after separate transactions involving PJM. Such transactions also have loop-flow impacts of the kind that led the New York ISO to ban certain paths in 2008, Dadourian said.
To stop these transactions, the monitor recommends eliminating the Ontario interface price and requiring scheduling of complete paths, instead of “patching together” transactions with separate eTags.
Priorities
In answer to a stakeholder question at the end of the session, Bowring said the Monitor’s biggest priority is fixing problems with the capacity market — issues now before stakeholders and FERC. He also cited concerns over up-to congestion trades, allocation of uplift charges and scarcity pricing.
Coal plant retirements will boost PJM on-peak energy prices by $3 to $4/MWh — and as much as $11/MWh if gas prices increase — according to a study released last week by The Brattle Group.
(Source: The Brattle Group)
The analysis — which evaluates the “feedback” effects from coal plant retirements, retrofits and increased gas demand on capacity and energy prices — is a case study of PJM’s Mid-Atlantic (MAAC) region.
Brattle said the retirement of 2.8 GW of coal capacity in MAAC, 15% of the region’s total, would increase on-peak prices $3-4/MWh by 2015, assuming delivered gas prices of $5-6/MMBtu. The impact would decline to about $1/MWh by 2025 as new gas-fired plants increase supply. Off-peak prices would increase by $1-2/MWh under the same scenario.
If all of the replacement capacity came from combined cycle units and combustion turbines, however, the increased fuel demand would boost gas prices by 5% to 10%. As a result, on-peak prices could jump more than $10/MWh by 2015, declining to $6/MWh by 2025. Off-peak prices would increase about $5/MWh throughout.
The analysis compared projected prices with futures prices for the PJM-West hub as of summer 2012. It noted that PJM West prices in October 2013 were about $5/MWh lower than the 2012 baseline.
The increase in margins — with a present value of $100-300/kW — “are not likely to be large or persistent enough to alter the extent of overall plant retirements,” Brattle said but could be enough to reverse some retirement decisions.
Capacity Price Impact
Capacity prices will rise in the short-term as reserves drop but drop long-term as increased energy prices reduce the net Cost of New Construction Entry (net CONE). “This effect decreases the long-run equilibrium price of capacity until the energy price impacts of retirements disappear,” the study said.
While numerous studies have projected the volume of coal capacity likely to retire and undergo retrofits, Brattle said few studies have evaluated the impact of these changes on energy and capacity prices and the feedback effects on plant economics. (A 2011 MISO study estimated an increase of up $4.80/MWh in its region due to environmental regulations. Exelon predicted in 2011 that the regulations could increase PJM prices by $12/MWh.)
Caveats
Note: For On-Peak Energy Prices.
The size of the price increases will depend on the amount and timing of plant retirements, the spread between coal and gas prices and the mix of peaking, intermediate and baseload generators that enter the market. The study did not evaluate the impact of retirements on renewable generation or new transmission projects, which in turn would also influence power prices.
Brattle also cautioned that its results did not take into account other potential changes in the market. “For instance, it is possible that a material portion of the nuclear fleet in the U.S. will shut down if gas prices and resulting wholesale power prices continue to be low. And gas usage itself could increase sufficiently that it begins to dampen its own attractiveness.”
The study included a sensitivity analysis to determine the impact if natural gas prices remain at current levels of $3-4/MMBtu. Under this “Low Gas” scenario, coal retirements had almost no impact except for near-term on-peak prices. “This is not surprising because the coal plants that would potentially retire are the less efficient ones and they would not run a lot under such low gas prices if remained in-service. Thus, the marginal units that set the market prices would stay the same whether or not the coal plants retire.”
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.
