Combined cycle generators’ performance in providing Tier 2 synchronized reserve has fallen by half since 2008, according to a new analysis provided to the Operating Committee last week.
(Source: PJM Interconnection, LLC)
In response to earlier stakeholder questions, PJM staff analyzed SR response rates since 2002 by generator type. They found that combined cycle units, which once had the best performance rates — averaging over 100% for all but one year during 2002-2008 — now is the worst performer, at below 60% (see chart).
PJM’s Tom Hauske, who presented the findings, said there’s “no obvious” explanation for the decline. “I assume it has something to do with how [plant operators] are optimizing their output now and they don’t have as much margin to move” when synch reserve events are called, he said.
While combined cycle rates have declined, the performance of hydro units and combustion turbines has been relatively constant, as have steam units, excluding a two-year jump in performance in 2010-2011.
Retrofits and other planned outages will make it challenging to maintain reserve margins in 2014 and 2015 and PJM will likely need to reschedule some outage requests as a result.
PJM’s Dave Schweizer briefed the Operating Committee last week on planned outages scheduled and anticipated for the two-year period, which will see 46 units totaling 7,725 MW of generation retire and 59 units totaling 25,890 take outages for retrofits.
PJM is awaiting retrofit/retirement decisions from the owners of 21 units totaling 3,456 MW.
The 2015 analysis shows the combination of scheduled and anticipated outages reducing generation below PJM’s targeted 15% reserve margin in May and September 2015, meaning officials will need to reschedule some shutdowns to months with more margin.
Projections also anticipate tight operations in May and September 2014.
“The key takeaway: If you’re a generation owner … please submit these (planned outage) tickets as soon as reasonably possible,” Schweizer said.
Steam generators that currently correct their capacity ratings to reflect ambient temperatures make changes averaging less than 1%, meaning new rules requiring corrections of all steam units should not have a major impact on PJM operations.
The largest change among the units that currently correct — representing 58% of PJM’s installed capacity (ICAP) — was 2%.
“At least for the units that already temperature correct, we’re not seeing a major change in their ICAP ratings,” PJM’s Tom Falin told the Planning Committee last week.
About half of PJM’s steam units already adjust their ratings although Manual 21 requires adjustments only for combustion turbines and combined cycle plants. Falin said the committee will be asked to endorse manual language adding the correction requirements for nuclear, coal and oil units as soon as January.
PJM predicts summer peak loads will increase by about 1% annually over the next decade, with a 1.4% increase in 2014, according to a draft forecast outlined to the Planning Committee last week.
The 2014 load forecast reduces peak and energy forecasts from the 2013 report due to revisions to historical economic data and the addition to the PJM model of another year of load experience.
(Source: PJM Interconnection, LLC)
A restatement in federal economic data made “the recent recession a little less deep and the recovery a little faster than data used in last year’s forecast,” PJM’s John Reynolds told the committee.
The projected 2014 summer peak is 157,399 MW, an increase of 2,214 MW from this summer’s weather normalized peak of 155,185 MW.
The RTO summer peak is projected at 173,852 MW for 2024 (an annualized increase of 1%) and 180,137 MW in 2029 (0.9% per year).
Compared to the 2013 load report, the new forecast reduces the anticipated summer peak for the next delivery year (2014) by 1,318 MW (-0.8%); the next RPM auction year (2017) by 2,777 MW (-1.7%) and the next RTEP study year (2019) by 3,457 MW (-2.0%).
Individual zones are expected to see average annual load growth of between 0.4% (RECO) and 1.8% (DOM) over the next 10 years. Several zonal forecasts were adjusted to account for large, unanticipated load changes:
AEP: The closure of the Ormet Corp. aluminum smelter in Hannibal, Ohio — the largest single load in PJM — reduced the summer peak by 370 MW in all years;
APS: 80-120 MW were added to the summer peak to reflect expansion of hydraulic fracturing facilities;
BGE: An “undisclosed project” currently under construction adds 120-315 MW to the summer peak;
DOM: Data center construction adds 288-896 MW to the summer peak.
Assumptions for future load management also have decreased from the 2013 report, to 12,400 MW from 14,600 MW. Projected energy efficiency was reduced to 900 MW from 1,100 MW.
Winter peaks are expected to grow by 0.9% annually over the next decade (to 144,496 MW) and 0.8% over the next 15 years (148,423 MW). Individual zones are projected to grow by 0.3% (ATSI) to 1.7% (DOM) annually for the decade.
Reynolds and Paul McGlynn, PJM general manager of system planning, asked transmission owners for feedback on the projections in their zones. “PJM does not have a deep understanding of what’s going on in Richmond and Allentown and Columbus,” Reynolds said.
Economist James Wilson, consultant to the public advocates of New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia, questioned what he called the “exogenous adjustment” to the BGE projection.
“Does it make sense to increase the BGE zone based on new load given the chronic over forecast in that zone?” he asked. Despite PJM predictions of increasing load, Wilson added, “The peak in BGE has gone sideways since 2005.”
Wilson also questioned PJM’s authority to make changes based on anticipated load additions. Manual 17, he noted, refers to adjustments for “load that’s already been experienced.”
“The plain language of the manuals does not authorize this sort of adjustment,” Wilson said. The change, he added, “has the potential to contribute to an RPM price spike.”
“We have not interpreted the manual that way recently,” Reynolds responded. “PJM and members wanted this.”
“Maybe we need to do a manual cleanup” to address the discrepancy, he acknowledged.
DuPont started up a 548-kW solar installation on a former Superfund landfill site in Newport. The project, developed by Tangent Energy Solutions and owned by Greenwood Energy, had its solar panels supplied by DuPont Apollo, a DuPont subsidiary.
The Environmental Law and Policy Center’s suit against Midwest Generation can go ahead, a bankruptcy judge ruled. The group alleges groundwater pollution from coal ash at the Romeoville, Pekin and Joliet generating plants, now owned by NRG Energy. The suit was put on automatic stay when Midwest Gen filed for bankruptcy, a stay the judge has now lifted.
Continuing a long dispute, Exelon appealed Ogle County’s $509 million tax assessment on its Byron nuclear plant, which the company says should be cut by half. Exelon paid $32 million in taxes on Byron this year.
The Public Service Commission granted Baltimore Gas and Electric $106 million in distribution rate increases and reliability riders, cutting the company’s request by more than half and denying the higher rate of return the company had sought.
The $33.6 million distribution rate increase, effective Dec. 31, was only 41% of the request. For BGE’s proposed Electric Reliability Initiative, the PSC approved five of eight proposed five-year programs for a total expenditure of $72.6 million instead of $136 million. The return on equity for electricity operations was kept at the current 9.75%; BGE had asked for 10.5%.
The Democrat-controlled Senate Environment and Solid Waste Committee approved a resolution (SCR146) that would have voters decide on a constitutional amendment to have the state return to participating in the Regional Greenhouse Gas Initiative, which Gov. Chris Christie pulled out of in 2011. A constitutional amendment would put the matter out of Christie’s hands. But Assembly Democrats are not seen likely to take up the resolution, if the full Senate passes it.
Massive wind farms offshore New Jersey and New York would have cut Hurricane Sandy’s winds by 65 mph and the accompanying storm surge by 21%, according to a Stanford University research team. The analysis assumed 70,000 offshore turbines capable of generating 300 GW. A similar “wall of turbines” offshore New Orleans would have reduced the power of Hurricane Katrina, the team said.
Duke Energy Progress put in service its new 625 MW L.V. Sutton combined-cycle gas plant at Wilmington. The plant, with modern pollution controls, replaces a 59-year-old 575 MW coal plant that Duke retired. The company soon will start deconstructing the coal units and “effectively closing” the coal ash basins, which are the subject of a lawsuit by the Southern Environmental Law Center for leakage that allegedly has damaged groundwater and Lake Sutton fish.
In its final public hearing as it contemplates whether to change the state’s retail electricity regime, the Public Utilities Commission heard from competition advocates supporting expansion of deregulation and from consumer advocates warning that customers need regulatory protection. The PUC’s examination of the issue began last year and has no timetable for completion.
Legal disputes are creating more delay for the proposed 200 MW Buckeye Wind Project. Everpower Renewables had hoped to start building in the spring, but challenges from Union Neighbors United, Champaign County and others continue to mean uncertainty and postponement of construction.
The Nuclear Regulatory Commission backed off its initial finding that FirstEnergy’s Beaver Valley station in Shippingport required extra monitoring because of its performance in a mock attack in April. In what an NRC spokesman described as an unusual decision, the agency concluded after further discussion with the company that no security-related incident had occurred.
The Senate confirmed Christopher Abruzzo as secretary of the Department of Environmental Protection, where he had been acting secretary since Gov. Tom Corbett appointed him in April. Previously he was deputy chief of staff in Corbett’s office. His confirmation was preceded by a small firestorm following statements about climate change at his confirmation hearing.
The Public Service Commission approved American Electric Power’s plan to transfer complete ownership of its 2,900-MW John Amos plant to AEP’s West Virginia unit, Appalachian Power. ApCo already owned all but 867 MW. The commission deferred a ruling on the company’s proposal to transfer half-ownership of the Mitchell plant to ApCo and on its request to merge AEP’s Wheeling Power with ApCo.
Virginia regulators had already rejected the Mitchell plant deal, and the PSC said there was no reason for it to rule on it now. The PSC said it deferred action on the merger because the Amos transaction alone would resolve ApCo’s generation capacity deficit until at least 2015.
The Beech Ridge Energy wind farm in Greenbrier and Nicholas counties is the first wind project to implement a habitat conservation plan for Virginia big-eared bats and among the first to implement such a plan for the Indiana bat. A Fish and Wildlife Service permit containing the plans for the 100 MW project covers 67 existing turbines and up to 33 more. Beech Ridge is a subsidiary of Invenergy.
(Source: CT Dept. of Energy & Environmental Protection)
Democratic governors from Maryland, Delaware and six other Eastern states yesterday asked the Environmental Protection Agency to impose controls on coal pollution they say is damaging air quality in their states.
The aggrieved states want EPA to force nine “upwind” states — Illinois, Indiana, Kentucky, Michigan, North Carolina, Ohio, Tennessee, Virginia and West Virginia — to join them as part of the Ozone Transport Region (OTR), which would trigger tougher emission controls.
Three OTR states headed by Republican governors, Pennsylvania, New Jersey and Maine, declined to join in the petition.
The states’ filing came the day before the Obama administration is set to defend its air pollution rules before the Supreme Court and a federal appeals court.
The Supreme Court will hear arguments today on EPA’s 2011 Cross-State Air Pollution Rule (CSAPR), which was struck down last year by the U.S. Court of Appeals for the District of Columbia Circuit.
The D.C. Circuit, meanwhile, is scheduled to hear challenges to EPA’s December 2011 mercury and air toxics standards (MATS) for power plants.
WASHINGTON — The cost of complying with upcoming carbon emission caps will depend on the role of energy efficiency and the choice of “blended” or fuel-specific emission standards, speakers told a high profile forum here last week.
A popular parlor game in Washington these days is debating what the Environmental Protection Agency’s pending greenhouse gas rules on existing power plants should look like. Will it be a rate-based standard limiting emissions per MWh or a mass-based standard, similar to the overall emissions “budget” used by California and the Regional Greenhouse Gas Initiative (RGGI)? Will limits be uniform or recognize states’ varying fuel mix?
About 400 people were in attendance as the Bipartisan Policy Center and the National Association of Regulatory Utility Commissioners turned a conference room at the Marriott Metro Center into a large, web-cast parlor. While there was no consensus on what EPA will do, there were plenty of opinions on what it should do.
Supporters of the mass-based standard said the rate-based alternative could result in uneconomic plant operations due to “seams conflicts” among states with different systems.
Kathy Kinsey
“If you’ve got states with 50 different programs you’ve got seams” said Kathy Kinsey, deputy secretary of the Maryland Department of the Environment. “That gets pretty complicated.”
“State borders are incongruous with energy markets,” said Dallas Burtraw, senior fellow at Resources for the Future, a think tank.
Bruce Phillips, director of The NorthBridge Group, said the rate-based alternative could also cause an “emission “rebound” as coal units that reduce their heat rates to comply are dispatched before gas plants, thus extending their operating lives.
Phillips argued for a mass-based approach that sets a “budget” for coal emissions and a separate emission rate for gas plants rather than a “blended” budget for both fuels.
Bruce Phillips
Both mass-based approaches could cut carbon emissions from fossil fuel generation and coal generation by 26% over 2005 levels while increasing gas consumption by 2.7 TCF and boosting Henry Hub gas prices by about 10%, Phillips said.
But while the fuel-specific approach would increase wholesale electric costs by 6%, prices would rise 28% under a blended approach, Phillips said.
Energy Efficiency’s Roles
The forum also featured a debate between the Natural Resources Defense Council and the American Coalition for Clean Coal Electricity (ACCCE) over the role and cost of energy efficiency under the new rules.
The NRDC has proposed a plan that would grant credits to state energy efficiency programs, which generators could purchase to effectively lower their average emissions rates. Dan Lashof, director of NRDC’s climate and clean air program, told the forum its plan could cut CO2 pollution by 26% from 2005 levels by 2020.
The environmental group initially estimated a compliance cost of $4 billion in 2020, which it said would produce environmental benefits of $25 to $60 billion. A revised analysis, incorporating lower demand growth estimates and energy efficiency costs, projects 2020 compliance costs at less than $1 billion.
Sound too good to be true? It is, insisted Paul Bailey, ACCCE’s senior vice president for federal affairs and policy.
Paul Bailey
Bailey presented an analysis “bookending” the NRDC proposal between two scenarios: “Maximum flexibility,” which envisions national emissions trading and credits for end-use efficiency and new renewables and “limited flexibility,” which allows only intra-state trading and no credits for EE or renewables.
Where NRDC sees 210,400 net job gains in 2020, ACCCE says it will cost 75,000 to 214,000 jobs. ACCCE also predicts retail price increases of more than 10% in 13 to 29 states.
Bailey said the main reason for the disparities are differing assumptions regarding energy efficiency costs. NRDC estimated costs of up to 4.6 cents per KWh while ACCCE used an estimate more than twice as high at 11 cents.
Other speakers also split on the role of energy efficiency.
Bruce Braine
“In the future, it’s going to be a challenge” to increase EE further, said Bruce Braine, AEP’s vice president for strategic policy analysis.
Resources for the Future’s Burtraw said a flexible approach allowing emissions rate averaging or trading and reliance on EE could result in a “very small change in electricity prices.”
State Standards
Kinsey said EPA should set uniform carbon intensity standards for all states while giving coal-dependent states time to adjust.
But the NRDC would set different levels. For example, California, which has virtually no coal generation would have a limit of 1,100 lbs./MWh while Kentucky would have a limit of 1,480. “While Kentucky would have a lower standard than California it would have to make a bigger reduction from its starting point,” said Lashof.
Nuclear Power Role
William K. Reilly
Keynote speaker William K. Reilly, EPA administrator from 1989-93, said the rules should allow generators time to recover their investments in emission controls for mercury, sulfur oxides and nitrogen oxides.
Reilly and other speakers also called for a renewed role for nuclear power, saying a reliance on natural gas alone for baseload power would expose the economy to price risk.
Six nuclear plants with a capacity of almost 4,900 MW have recently announced retirements due to flat power demand and low prices.
Kathleen Barron
If that trend continues, the nation will lose one-quarter of its nuclear capacity by 2025 — giving back more than half of the progress to date in meeting 2020 climate goals, said Kathleen Barron, Exelon Corp.’s , senior vice president for federal regulatory affairs and wholesale market policy. “All of these pictures, of course, change if there’s a price on carbon,” she said.
EPA Approach Praised
Speakers praised EPA’s efforts to solicit input from industry and state regulators in formulating the rules. “I’ve seen EPA personnel more than my own family in the last few months,” joked Doug Scott, chairman of the Illinois Commerce Commission.
Among those in attendance were Gregory Carmean, executive director of the Organization of PJM States Inc. (OPSI), and PJM market strategist Gary Helm, Vice President for Federal Government Policy Craig Glazer and Chief Economist Paul Sotkiewicz.
“It’s pretty clear that people are looking for flexibility in what EPA proposes,” Sotkiewicz said after the session. “Flexibility across fuel sources, flexibility across geographic regions, flexibility across time.”
Third time was the charm yesterday as members approved Tariff changes that will allow PJM operators more flexibility in dispatching demand response.
Meeting in a special session, the Members Committee approved an amended version of the changes after rejecting the original PJM proposal and one alternative. The third vote passed after an amendment that won over manufacturers.
Changes
PJM said its experience during two heat waves this summer demonstrated the need for changes to allow quicker and more targeted use of demand response.
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.
The new rules also limit the “Emergency DR” designation to resources using back-up generators that are subject to environmental permits. Other resources will be known as “Capacity DR.”
In addition, the minimum event duration will be reduced from two hours to one hour and the strike price will be reduced by 22% to 39% (see chart).
DR Opposition
The proposal passed over the objection of Curtailment Service Providers, who said they agreed with the need to increase DR’s flexibility but disagreed with how PJM was seeking to accomplish it.
Bruce Campbell, of EnergyConnect, said the changes will increase CSPs’ administrative costs and reduce the volume of DR, leading to increased costs for PJM load. He added, “It is retroactive ratemaking and we should not be doing it.”
David “Scarp” Scarpignato, of Direct Energy, argued unsuccessfully for a slower transition to the 30-minute default. He said Direct will challenge the changes when they are filed with the Federal Energy Regulatory Commission.
Katie Guerry, representing EnerNOC, said only a “small minority of customers” can reduce their loads within 30 minutes. PJM’s reliability will not benefit, she said, if it attempts to enforce a lead time “that is simply not physically practical.”
CSPs also complained that PJM had not incorporated changes to its measurement and verification rules.
Votes
The PJM proposal failed with a sector-weighted vote of 2.74 (55%), below the threshold of 3.34 (two-thirds). The proposal had won 67.4% support of the Markets and Reliability Committee Nov. 21, just enough to clear the two-thirds hurdle.
A second proposal, which included an amendment to increase the maximum dispatch time to 120 minutes for state-authorized “mass market” DR programs, also fell short at 2.85.
The third vote cleared by a 3.52 (70%) vote after winning support from manufacturers.
Crucial Amendment
Susan Bruce said some members of the PJM Industrial Customer Coalition could not support the proposal as originally drafted because it allowed manufacturers an exemption from the 30-minute dispatch only if they needed to do so to “avoid damaging major industrial equipment.”
As approved, that clause was amended to also allow manufacturers an exemption if needed to avoid damage to “product or feedstock.” It also included the maximum 120-minute notification for mass market programs.
Big Rivers Electric Corp. said it will lay off 165 workers when it idles two generating plants in response to loss of the two Century Aluminum smelter customers. It expects to idle the 417-MW Wilson plant in February and the 443-MW Coleman plant by June. The company has said the customer departure makes 65% of its generating base redundant and means a $360 million annual revenue loss.
NRG’s Chalk Point Generating Station in Prince George’s County, MD(Source: Wikimedia)
NRG to Shut 5 Coal Plants in 2017
NRG Energy told PJM it plans to retire five coal-fired generators at two sites in Montgomery and Prince George’s counties in 2017 due to low natural gas prices and potential environmental costs. Dickerson units 1-3 and Chalk Point units 1 and 2, with a combined capacity of 1,200 MW, were the subject of a water-pollution suit by state regulators.
The closure would leave the state with only five coal-fired generators, according to the Sierra Club. NRG said it will continue operating gas- and oil-fired units at the two sites.
Exelon plans to retire the natural gas-fired Unit 4 at its Riverside Generating Station in Baltimore County, citing the 74 MW unit’s age, maintenance costs and falling revenue. The move comes as Exelon plans to build two 60 MW gas units in Harford County, part of its commitment to add clean generation in Maryland.
The Army has hired Ameresco to install 18.6 MW of solar power at Fort Detrick. An environmental assessment will be performed before a final contract can be signed. The fort is one of five Army “NetZero” pilot sites to seeking to create as much energy as they consume.
The Pinelands Commission unexpectedly rejected a deal South Jersey Gas had reached with the Board of Public Utilities to lay a gas pipeline through the Pinelands to repower Rockland Capital’s BL England plant. The conversion of the 447 MW coal and oil plant was widely supported as a way adding supply to replace part of the capacity that will be lost with anticipated closing of the Oyster Creek nuclear plant in 2019.
But commissioners said they were not satisfied with environmental protections and that the company’s offer of $8 million for land preservation made it look as if they were being paid off. Assertions that the pipe would have little impact on the Pinelands are “ridiculous,” said one commissioner.
State Senate President Stephen Sweeney said the Christie administration has moved too slowly on offshore wind development, costing the state at least 1,000 jobs. Sweeney spoke as Environment New Jersey released a report promoting the benefits of offshore wind development. One of the obstacles to moving ahead on development goals, Sweeney said, is the lack of progress on regulations for wind energy credit sales. The Board of Public Utilities has not said when the regulations will be ready.
Duke Energy is disputing a study commissioned by the Southern Environmental Law Center that says selenium from Duke’s coal ash ponds is killing fish in Sutton Lake in Wilmington. The utility retired its coal plant there last month. The law center has joined a state suit seeking removal of the ash.
A 36-acre solar farm will put a big dent in property values – and already has done so — residents say as Strata Solar tries to get Lincoln County approval for the facility.
Duke Energy Renewables is building three solar projects totaling 30 MW in the eastern part of the state. SunEnergy1 will design and build the projects.
A 40-turbine wind farm proposed for Carteret County will endanger military pilots and jeopardize activity at Marine Corps Air Station Cherry Point, speakers at a community forum said. The wind farm, together with a solar array, is proposed by Torch Renewable, which would sell the output to Duke Energy Progress.
Euclid City Council joined other local governments in announcing its support for Lake Erie Energy Development Corp.’s offshore wind project. LEEDCo’s Icebreaker project, a six-turbine, 18 MW pilot, is targeting a 2017 date for beginning operations.
Action on a bill that has roiled Ohio energy interests for weeks was postponed again as green energy advocates pushed back against the measure to reduce the state’s efficiency and renewable energy mandates. Sponsor Sen. William Seitz says he will continue pursuing ways to reduce the state’s “envirosocialist” requirements.
PPL Electric Utilities’ plan to upgrade a 24-mile line in the Pocono plateau won Public Utility Commission approval. The $33 million project will replace the existing 69 kV line with a double-circuit 138 kV line. The plan drew no local opposition.
PPL finished the upgrade of its Holtwood hydropower station on the Susquehanna River, with its 125-MW addition more than doubling the facility’s capacity to 230 MW. The company expects to qualify for federal stimulus funds, which it said were a critical factor in deciding to upgrade the century-old site. The dam features the largest fish lift in the country.
Fifteen Beaver County residents have sued FirstEnergy for damages over contaminants from the utility’s 1,900-acre Little Blue Run coal ash disposal site. The suit follows a similar one filed by West Virginia residents. Meanwhile, environmental groups and the state Department of Environmental Protection disagree about the opportunity to comment on FirstEnergy’s proposal to barge the ash from Little Blue Run to another site. Environmentalists say a permit could effectively be issued before they have a chance to see the final plan.
Consol Energy’s Enlow Fork mine in Washington County could monetize methane capture by participating in California’s greenhouse gas cap-and-trade market. The California Air Resources Board is to vote early next year on a proposed program to award credits for mine methane projects. Because greenhouse gas emissions contribute to global warming, projects anywhere in the U.S. can qualify under California’s system.
Virginia could be “the Silicon Valley of wind development” in the East, the chairman of the Virginia Offshore Wind Development Authority said upon release of a report detailing potential benefits. The report was released as Dominion continued work on a 12 MW demonstration project.
Despite opposition from big institutions and historic preservation interests, the State Corporation Commission approved an 8-mile, 500-kV power line Dominion plans to build across the James River near historic sites. The Surry-Skiffes Creek Project is essential to reliability, the SCC said.
Dominion Virginia Power will install the commonwealth’s largest rooftop solar project on Canon Virginia’s manufacturing facility in Gloucester. The 500 kW project is part of the utility’s Solar Partnership Program.
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.
