(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.
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.
