PJM’s Market Monitor has weighed in on a MISO dispute over whether generation owners can be compensated for their plants’ sunk costs when the plants are prevented from retiring in order to maintain grid reliability.
In July, the Federal Energy Regulatory Commission found that MISO’s Tariff rules concerning system support resources (SSRs) were unjust and unreasonable because they did not compensate generation owners for their SSR units’ fixed costs, only their going-forward costs. Under MISO’s Tariff, the ISO may designate a plant that is scheduled to be retired or suspended as an SSR if it finds that the plant is necessary to main grid reliability.
The PJM equivalent to the SSR is the reliability-must-run (RMR) unit.
In a filing last month (EL13-76), PJM’s Market Monitor asked FERC to clarify its ruling.
“If by ‘fixed costs,’ the commission only means fixed costs incurred specifically to provide SSR service, the Market Monitor requests clarification on that point,” the Monitor said. “The Market Monitor respectfully urges that if a finding that sunk fixed costs should be recovered through SSR service rates was intended, that such a finding be reversed.”
The Monitor argued that generators scheduled to retire were likely not recovering all of their sunk costs when they were operating. Allowing a generator to recover sunk costs through the market in a SSR agreement would create the unintended incentive for generators to retire their units prematurely, the Monitor said.
“The goal of an SSR service agreement should not be to provide a windfall that the market would not otherwise provide,” the IMM said.
Instead, the IMM recommended that MISO provide an incentive rate for SSR units, as PJM does for its RMR units.
FERC’s ruling stems from a July 2013 complaint by Ameren, which at the time owned the Edwards coal-fired plant near Peoria, Ill. After Ameren decided to retire the plant’s 90-MW Unit 1, MISO designated it as an SSR.
Ameren had asked FERC to rule that the definition of “going-forward costs” in SSR agreements include fixed costs and requested that about $12.8 million be included in the Edwards SSR agreement. Illinois Power Holdings, a subsidiary of Dynegy, bought the plant last December and asked for another $5 million.
The Nuclear Regulatory Commission approved a new rule on spent nuclear waste, ending a two-year suspension of licensing decisions after a court invalidated the old rule.
The new rule, called the “Continued Storage of Spent Nuclear Fuel,” adopts findings from a generic environmental impact statement and concludes that spent nuclear fuel can be safely managed in dry casks for more than 100 years. However, the NRC stressed that “The rule does not authorize, license or otherwise permit nuclear power plant licensees to store spent fuel for any length of time.” Adoption of the new rule allows the NRC to lift the licensing moratorium.
The NRC wasted no time resuming licensing decisions. Two days after the new rules were approved, the agency issued a final environmental impact statement for Exelon Nuclear’s Limerick Generating Station in Pennsylvania. The licenses for the plants two reactors expire in 2024 and 2029. The relicensing still requires final approval from the NRC’s Office of Nuclear Reactor Regulation.
Exelon Nuclear can go ahead with a plan to increase power production from its two reactors at the Peach Bottom Atomic Power Station in Delta, Pa. The Nuclear Regulatory Commission approved a plan to bump up each of the boiling water reactors by 140 MW. The company says it will upgrade the reactors during refueling outages, once this fall for Unit 2 and again in the fall of 2015 for Unit 3.
A wafer of plutonium-239 fell from its holder and broke in half at a federal lab in Maryland, but no workers were contaminated and the lab was cleaned up. The wafer was being used in a neutron radiation procedure when the incident occurred at the National Institute of Standards and Technology’s Research Reactor Test Facility in Gaithersburg on Aug. 29. After it fell, lab workers retrieved it, put it in a safe and decontaminated a single spot of radiation where it fell.
New U.S. distributed wind deployments declined 83% in 2013 to 30.4 MW, according to a Department of Energy report issued last week. The decline in new generation designed for local loads was in line with the overall shrinkage in wind installations last year following the expiration of federal production tax credits.
The Distributed Wind Energy Market Report said 2,700 units were installed last year in 36 states, Puerto Rico and the U.S. Virgin Islands. Residential installations made up 40% of the market, followed by agricultural at 26% and commercial and industrial at 20%.
Since 2003, 72,000 wind turbines in distributed applications have been installed in the U.S., representing 842 MW in capacity. The top states for distributed wind were Colorado, Kansas, Ohio, Massachusetts, Arkansas, Indiana and North Dakota.
The Environmental Protection Agency is considering rules to force gas well drillers to cut methane emissions, EPA Administrator Gina McCarthy said. McCarthy, speaking to investors in New York last week, said the agency will decide this year whether to issue regulations to reduce fugitive methane emissions, or depend on voluntary cuts from the drilling industry.
Methane is 21 times more potent than carbon dioxide, the target of the Agency’s recent, sweeping emissions rules. “We are looking at what are the most cost-effective regulatory and/or voluntary efforts that can take a chunk out of methane in the system,” McCarthy said. “It’s not just for climate, but for air quality” reasons, she said.
The Department of Energy has awarded $7.25 million to six organizations working to develop marine and hydrokinetic technologies to generate power from waves, tides, rivers and ocean currents.
Pacific Northwest National Laboratory, the University of Washington, Scientific Solutions, Florida Atlantic University and Oregon State University will share $3.5 million in grants for instrumentation research. A consortium of Oregon State, the University of Washington and the University of Alaska Fairbanks will get $4 million for research to accelerate the development and deployment of wave and tidal power technologies.
DOE Report Shows Progress in Offshore Wind Industry
Two offshore wind projects are in the initial stage of construction and 14 more are in advanced planning stages, according to a federal report issued last week. The Offshore Wind Market and Economic Analysis, issued by the Department of Energy, says the 16 projects represent nearly 4,900 MW of potential offshore wind energy capacity.
The report details the construction progress of the Cape Wind and Block Island projects in New England. It also noted that three other offshore projects – Fishermen’s Energy off New Jersey, Dominion off Virginia and Principal Power off the coast of Oregon – received up to $46.7 million each for final design and construction.
The Montana Public Service Commission has cleared the way for PPL Montana to sell 11 hydro facilities and a reservoir to NorthWestern Energy for $900 million. The divestitures are separate from PPL’s plan announced earlier this year to spin off its merchant generation. The Federal Energy Regulatory Commission has already approved the sale of the hydro facilities, which generate 630 MW.
Firms Advance Plan to Build 2-Unit Nuclear Plant in Utah
Westinghouse Electric Company and Blue Castle Holdings have signed a memorandum of understanding to build a new nuclear generating station in Utah. The two companies agreed to work together on all phases of a plan to build a plant using two of Westinghouse’s AP1000 reactors.
Under the agreement, the firms will pursue licensing and permitting while continuing engineering studies. Blue Castle says it does not intend to build the plant, but it wants to develop a comprehensive plan with approvals in place that it can turn it over to a utility or other company to build. Two other projects in the U.S. are using the AP 1000 reactors, as well as two sites in China.
Duke Energy Shuts Down Ohio Plant Ahead of Schedule
The last two coal-fired units at the 60-year-old Beckjord Station in New Richmond, Ohio, were shut down last week, the victim of increasingly stringent emissions regulations, Duke Energy said.
The company had planned to shut down the two units by January but said they had become uneconomical. Four other units at the plant have been shut down in recent years – two in 2012, one last year and one this year. Four other oil-fired units will remain in service. The plant was the site of a spill of about 9,000 gallons of fuel oil last month. The spill briefly shut down traffic on the Ohio River.
Duke Energy is seeking a license renewal for its 867.5-MW Keowee-Toxaway hydro facility on the Savannah River. The facility has components in both North Carolina and South Carolina. Duke is asking the Federal Energy Regulatory Commission for a license to operate the facility for between 30 and 50 years. It was originally licensed for 50 years in 1966. Duke has been working with regulatory agencies and a group of 16 stakeholder organizations on the relicensing project since last year.
Pa. Appeals Court Throws out Verdict Against PPL in Worker’s Fall
A Pennsylvania Superior Court panel last week threw out a $2.5 million lower-court jury verdict against PPL for injuries sustained by a man who fell 40 feet while painting one of the company’s transmission towers.
PPL argued that it was not liable for the actions of a contractor that employed Vincent P. Nertavich of Berks County, who was disabled from the 2009 fall. Nertavich argued that the accident was PPL’s fault for failing to provide adequate safety equipment. The appeals court ruled that Nertavich’s employer and not PPL controlled how the workers climbed the towers.
Wind-power advocates are concerned about Exelon’s proposed takeover of Pepco Holdings Inc., pointing to Exelon’s much-publicized campaign against extending a wind-energy subsidy.
Bruce Burcat, executive director of the Mid-Atlantic Renewable Energy Coalition, said his group has filed to intervene in the Exelon-Pepco case in Delaware. Delaware has been a supporter of wind energy, and Burcat said Exelon’s opposition to the federal production tax credit impedes wind development.
Exelon is poised to take over Pepco, parent company of Delmarva Power & Light in Delaware and utilities in New Jersey and D.C. Exelon, the nation’s largest reactor operator, has argued that the wind-power tax credit makes it difficult for other energy sources to compete.
Homeowners in the Potomac Crest neighborhood in Montgomery County, Md., obtained a restraining order to stop Pepco from trimming their trees until a full hearing can be held.
The company said vegetation management is critical to improving the reliability of its electric system, but customers said the company is going too far. One customer even stood in the way of trimming crews in an attempt to stop them. Residents said their land titles say nothing about having to let the company trim the trees.
But a company spokesman said it obtained access to the properties in 1959, 30 years before the neighborhood was built. The company promised to work with customers, but it said it has a right to keep cutting.
Contractors working at AEP’s James M. Gavin power plant in Ohio have sued the company, saying they were exposed to health risks at the plant’s coal ash landfill. Workers say they were inadequately protected from the coal ash, which they called a “radioactive amalgam of hazardous constituents that pose known risks for human health.”
AEP said they have observed all safety guidelines and operate the 246-acre landfill in a responsible manner.
“We have legally and appropriately operated the landfill at Gavin plant,” AEP spokeswoman Melissa McHenry said. “We believe the claims in the lawsuit are without merit and plan to vigorously challenge them.” Gavin, a 2,600-MW plant, is the largest in Ohio.
The suit names 77 plaintiffs, six of whom have died.
PJM’s plans to conduct winter tests of infrequently used generators could cost as much as $15.9 million, officials told the Operating Committee last week.
PJM’s Eric Hsia said a simulation indicates it would have cost PJM $743,000 to $795,000 in generator payments to test 1,000 MW of generation on Dec. 10, 2013, although some of the costs might have been offset by energy market savings.
Mike Bryson, executive director of system operations, said PJM hopes to test up to 1,000 MW of generation on each of 20 days in December 2014, making the “worst-case” total cost as much as $15.9 million.
The tests would be limited to generators that haven’t run in the prior eight weeks and days when temperatures are below 35 degrees Fahrenheit.
Bryson said the testing will likely be phased out if PJM’s Capacity Performance proposal, which includes new performance penalties and incentives, is approved. “Once the penalties are in place, this wouldn’t be needed,” Bryson said. (See related story, Members, Monitor Skeptical of Capacity Overhaul.)
John Farber of the Delaware Public Service Commission said customers shouldn’t have to pay for testing of generators that are receiving capacity payments to be available all 8,760 hours of the year.
“Customers are supposed to be paying for annual capacity,” Farber said. “They shouldn’t have to pay more.”
The testing costs could be at least partially offset by energy market savings if it reduces the forced-outage rate during the winter, one stakeholder said. PJM’s worst-case analysis “only shows half of the equation,” he said.
The OC will be asked to approve manual changes adding proposed testing rules in October. The proposed rules do not specify how testing costs would be allocated.
Meanwhile, the North American Electric Reliability Corporation will conduct a webinar Oct. 2 on “Winter Preparation for Severe Cold Weather.” The webinar will include a discussion of lessons learned from the 2014 polar vortex and the February 2011 rolling blackouts in the Southwest U.S.
Members agreed last week to consider changing credit requirements for virtual transactions in January and February 2015 despite opposition from PJM, which said changes could increase members’ exposure to defaults.
The Market Implementation Committee Wednesday approved a problem statement to consider changing the credit requirements for increment offers and decrement bids, which are based on nodal reference prices. Stephanie Staska of Twin Cities Power said the change is needed because extreme conditions last winter will result in much higher reference prices and credit requirements next winter.
Staska said the reference price for trades at the PJM West Hub for January and February 2015 would be about $316/MWh under current rules, meaning a 50-MW on-peak INC or DEC would require $250,000 in collateral. At a 5% cost of capital, it would result in credit costs 10 times higher than in the winter of 2014 and far higher than equivalent trades in MISO or on the Intercontinental Exchange (ICE), Staska said.
Staska said such an increase will hurt liquidity in PJM’s market.
Barry Trayers of Citigroup Energy backed Staska’s proposal. “Throwing [January and February] out as an anomaly makes sense to me,” he said.
But PJM Chief Financial Officer Suzanne Daugherty said if a change is approved by stakeholders, she will ask the Board of Managers to refuse to submit it to the Federal Energy Regulatory Commission for approval.
“I don’t know what prices are going to do in January and February, which is why it makes me anxious to make an exception,” she said. “An anomaly suggests it can’t happen again.”
Daugherty acknowledged that there were no defaults by INC and DEC traders last winter. But she added, “You don’t just look at what has defaulted in the past. You look at what might default.”
The problem statement was approved with no opposition but 41 abstentions. A related issue charge passed with one objection and 42 abstentions.
The matter will be assigned to the Credit Subcommittee, which is already conducting a more comprehensive review of INC and DEC credit policies.
The Public Service Commission wants to hire a consultant to help it review and assess the potential costs and benefits of retail aggregation. The job posting, done through the Secretary of State’s office, is part of a legislature-ordered study of aggregation, which would allow groups of residential and small commercial customers to band together to buy power. Only standard-offer customers of Delmarva Power & Light would be eligible to participate in an aggregation plan.
Retail natural gas customers of Delmarva Power & Light will pay less this winter, according to a filing with the Delaware Public Service Commission. The company said lower overall wholesale prices, and the ability to store natural gas, will allow it to reduce rates about 7.3% for residential customers and between 3.5% and 12.8% for commercial and industrial customers. The average monthly residential bill will decrease from about $139 to $126, the company said. The PSC is expected to approve the rate decrease in November.
Fracking Rulemaking Nears Final Steps After Public Input
The Department of Natural Resources has received more than 30,000 public comments on hydraulic fracturing, or “fracking,” in advance of setting final rules for the drilling process. The Joint Committee on Administrative Rules, which received the final draft of the rules last week, has until Nov. 15 to approve them. If it can’t, the process will start all over again. No drilling can start until the rules are finalized.
Industry supporters think the committee set too wide a net in collecting comments before setting the final rules. Mark Denzler, vice president and chief operating officer of the Illinois Manufacturers’ Association, which is part of a coalition that supports fracking, said an initial review “expanded the rules beyond what the legislation has set forth.”
Anti-fracking groups think the committee isn’t giving the issue the thought it deserves. “Fracking is a very dangerous practice that threatens the health, water supply and air quality of residents and Sierra Club is opposed to its use in Illinois,” said Jack Darin, director of the Illinois Chapter of the Sierra Club.
Duke Energy Indiana has proposed spending $1.9 billion over seven years to update its aging statewide electric grid to improve reliability for 800,000 customers. The state’s largest electric utility filed the plan with the Indiana Utility Regulatory Commission, saying its aim was to reduce the number and duration of outages.
The plan would improve power reliability and safety, reduce outages, and provide more accurate customer bills and quicker connections and disconnections. The company said the improvements will gradually increase rates about 1% between 2016 and 2022.
Customer advocates have already identified some concerns. “This is a lot of money that will result in significant rate impacts across all sectors of our economy, most notably fixed-income and vulnerable populations,” said Kerwin Olson, executive director of Citizen Action Coalition of Indiana.
The chief of staff of the Department of Health has been tapped to fill a vacancy on the Utility Regulatory Commission. James Huston, who has held federal and state positions for 30 years, was appointed by Gov. Mike Pence, who cited Huston’s “lifetime of public service.” Huston fills the seat left open when James Atterholt, the commission’s chairman, left to become Pence’s chief of staff. Carol Stephan was appointed the commission’s new chair.
A proposed computer data storage center, along with its own power plant, could find a home in the state after the University of Delaware nixed a plan to host it.
The Data Centers LLC wants to build the center, along with a 279-MW natural-gas fired power plant, and is now looking at sites in the state, including Cecil County, the northernmost county. The Public Service Commission would have to approve the plan.
The project calls for a 900,000-square-foot data center – about the size of five Wal-Mart supercenters – along with the power plant. The University of Delaware was moving forward to allow the project to be built next to its Newark campus, but community criticism sank the plan in July.
The state added more than 1,450 new clean energy jobs between April and June, ranking it third after Arizona and California. A report issued Thursday by Environmental Entrepreneurs (E2) notes that the state’s clean-energy policies helped spur investment in the sector. The Public Service Commission has said that since 2008, investors have pumped more than $2 billion into clean-energy projects.
When the bankrupt Revel casino shut down in Atlantic City last week – the latest gaming establishment to call it quits in New Jersey’s ailing gambling mecca – a final bit of business was left undone.
A $129 million heating and chilling plant, whose sole customer was the 47-story casino and hotel, could become another victim of the bankruptcy. The power plant, which is separately owned and operated from the casino, was funded by a $118.6 million loan backed by municipal bonds. So Atlantic City taxpayers could be left holding the bag.
Even though the hotel-casino is closed, the plant is still operating to prevent the empty tower from becoming infested with mold. Ongoing utility costs can run from $50,000 to $450,000 a month.
Energy producers have finally met a requirement for turning chicken waste into electricity, but they are asking the state Utilities Commission for more time to work their magic on pig manure. North Carolina is the only state that requires utilities to generate a set amount of electricity from poultry litter, which is collected from the floor of chicken houses and burned in incinerators.
The law says at least 170,000 MWh of electricity has to be produced from chicken waste this year. It also requires that at least 0.07% of electricity sold to retail customers must come from swine waste. Duke Energy Carolinas and Duke Energy Progress, along with other companies and electric cooperatives, have so far been unable to meet the swine target, and have filed for extensions.
The state Supreme Court last week sided with regulators over how much American Electric Power can charge customers for coal that fuels its power plants. AEP argued that it should have been allowed to keep all of the $71.6 million it received related to a coal contract. The Public Utilities Commission said some of the money should be credited to AEP customers.
The court’s unanimous ruling isn’t the final word on the issue. A related fuel charge dispute is still being reviewed by PUCO.
Sunoco Logistics Partners, which is repurposing and expanding a pipeline to transport shale-gas liquids to the Philadelphia area, is urging the Public Utility Commission to reject a recent recommendation by two of the commission’s own administrative law judges.
The recommendation held that the Sunoco project, the Mariner East pipeline, is not a public utility. Designating the pipeline project a utility would make it easier for it to bypass local zoning restrictions and help it with eminent domain rights. “The nature of Sunoco’s proposed service is private since it is limited to a selected few number of shippers and not available to members of the public,” the judges wrote.
Drilling of the first of 45 natural-gas wells planned for the Pittsburgh International Airport started last week with a ceremony attended by Gov. Tom Corbett and other politicians.
The wells, which tap into the gas-rich Marcellus Shale formation, are expected to bring more than $500 million in royalties to the Allegheny County Airport Authority. The project was approved in 2013. Consol Energy, which is developing the 9,000-acre airport property, paid a $50 million signing bonus to the authority, which allocated the money to fund improvements.
The first well is about a mile away from an active runway. Others are expected to be as close as a quarter-mile to the runways.
Williams Transco Gets OK to Build 100-Mile Pipeline
The State Corporation Commission has allowed Williams Transco to start construction on a 100-mile natural-gas pipeline that will deliver fuel to a new power plant near Lawrenceville. The pipeline will run through Pittsylvania, Halifax, Charlotte and Mecklenberg counties and terminate in eastern Brunswick County. The project is expected to take a year to complete.
Dominion Virginia Power is finalizing plans to construct a 1,358-MW, $1.3 billion natural-gas plant in Lawrenceville that will replace power now generated from coal. Construction of the plant is to begin in the summer of 2016.
Residents in Haymarket and Gainesville, Va., are already organizing opposition to Dominion Virginia Power’s plan for a six-mile run of 230-kV transmission line, two weeks after the project was announced. Residents and city officials are asking pointed questions about the planned route and the need for the power line.
The line, which would be installed on 120-foot-tall towers, would go through wetlands and come close to neighborhoods. Residents said they were told that the line was needed to serve growing demand for power in the area. But some residents became angry when Dominion later indicated the line would also serve the needs of a future customer that they wouldn’t identify.
The Public Service Commission has named a former federal transportation official as the new director of the state’s Gas Pipeline Safety Division. Mary S. Friend, who previously worked for the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, developed and taught training courses for federal and state pipeline inspectors. She started as a geologist at Columbia Gas Transmission and has been a member of the American Gas Association’s Gas Piping Technology Committee since 2006.
Trans Energy to Restore Streams, Pay $3 Million in Settlement
Oil and gas company Trans Energy agreed to restore portions of streams and wetlands at 15 West Virginia sites allegedly polluted from dredging operations during gas-drilling operations in 2011 and 2012.
The agreement with the U.S. Environmental Protection Agency, the West Virginia Department of Environmental Protection and the U.S. Department of Justice also calls for Trans Energy to pay a $3 million civil penalty.
The EPA alleged the company harmed streams and wetlands by discharging dredge or fill material during natural gas drilling operations. About 13,000 feet of streams and more than an acre of wetlands were impacted.
The NYISO Management Committee approved a mandatory black start requirement in part of in the Consolidated Edison territory, despite opposition by generators who said the previous voluntary system had been working well.
The committee approved the new rules with 63% support at its Aug. 27 meeting, clearing the 58% threshold.
Con Ed and the New York State Reliability Council say the program is needed to provide quicker service restoration in New York City (Zone J). Con Ed said no new black start resources have been constructed in the city since the New York energy markets opened in 1999.
The NYSRC is an independent organization governed by a 13-member executive committee representing transmission operators, wholesale generators and others.
Con Ed would be able to require black start service from generators that it can show would materially improve the speed, adequacy or flexibility of its plans for resuming operations after a blackout.
The ISO could grant a requested exemption for “good cause” — meaning that inclusion of a plant would be burdensome to the plant owner for technical, financial or other reasons.
The plan heads to the NYISO Board of Directors for final approval in October.
PJM officials said last week they will likely recommend that the Board of Managers approve 23 reliability projects proposed during the first solicitation window of the 2014 Regional Transmission Expansion Plan.
Twenty-two of the projects, totaling $82 million, are upgrades and would be awarded to the incumbent transmission owner in the zone.
PJM officials told the Transmission Expansion Advisory Committee they are still comparing several greenfield proposals against incumbent PPL’s proposed upgrade to correct overloads on the Montour–Milton–Sunbury 230-kV line. In addition to two upgrades proposed by PPL, PJM also received 10 greenfield proposals in the PPL zone ranging from $29 million to $164 million.
PPL has also proposed a new double circuit 500-kV line and substations spanning the PPL and Penelec zones at a cost of $1.367 billion.
The 22 “preliminary recommended solutions” ranged from $20,000 (closing a normally open switch) to $26.5 million (reconductoring a 230-kV line and upgrading terminal equipment). They were selected from 45 proposed transmission owner upgrades and 61 greenfield projects addressing about 50 facilities in 18 transmission zones.
Projects not recommended were either more expensive than the selected alternatives or addressed reliability issues related to expected generator retirements or additions. Projects addressing changes in generation will be reconsidered as retirements and additions are finalized.
Top Congestion Spots Identified
Planners also released the list of PJM’s 25 most costly transmission constraints in preparation for the opening of a second RTEP window that will include “market efficiency” proposals to reduce congestion.
The top 25 chokepoints are responsible for almost $539 million of the $593 million in projected congestion costs for 2015.
The analysis found congestion resulting from wind generation in the ComEd zone and being reduced by new generation planned for the MAAC and Southern PJM regions.
Rising load and natural gas prices are expected to add to congestion in future years. Higher gas prices after 2020 are expected to aid coal-fired generation.
Planners said they will conduct cost-benefit analyses to determine whether to accelerate planned reliability projects that also benefit market efficiency.
The second window, which will also include long-term reliability fixes, will be open from Nov. 1 through February 2015. PJM will finalize the proposal document and criteria for proposals in October after accepting feedback on the model through September.
‘Lessons Learned’ Poll Results
Meanwhile, PJM officials said they will work with stakeholders to improve the solicitation process based on feedback received in response to a poll conducted last month. Eleven topics received 10 or more votes in favor.
Commenters said PJM should develop and follow a step-by-step process consistent with its Tariff, including clear identification of the metrics the RTO will use to evaluate proposals.
Some respondents said incumbent TOs should be awarded responsibility for construction when PJM significantly modifies proposed projects to develop the most effective solution.
Planners were criticized in July for their recommendation that Public Service Electric & Gas be selected to fix the Artificial Island stability problem in southern New Jersey. PSE&G’s winning proposal was estimated at $1.066 billion before PJM planners eliminated two 500-kV lines from it, reducing the project’s cost by more than three-quarters. (See PJM Board Puts the Brakes on Artificial Island Selection.)
Others said proposal submission requirements should be more general for windows open for only 30 days than for 120-day windows. The 30-day windows would use high-level cost estimates, environmental analyses and power flow data to demonstrate the proposals’ effectiveness.
Dynegy said last week it may seek to move its Illinois generation to PJM unless MISO changes its capacity market rules.
The company is framing the issue as one of system reliability and consumer protection. However, there could be substantial financial benefits to Dynegy if its MISO generation were part of PJM, where capacity prices are far higher.
“MISO’s own forecasts show that it expects to be short of generation in the next few years,” Dynegy spokeswoman Katy Sullivan said. “The potential for consumer rate shock as the market moves across the vertical demand curve is high. Our point is that there are several ways for Illinois to address this concern and benefit all market participants.”
“Improving the MISO capacity construct is one,” she said, “moving to PJM is another.”
Dean Ellis, Dynegy’s managing director for regulatory affairs, first floated the potential move in an interview with Crain’s Chicago Business.
Why Switch to PJM?
MISO’s voluntary capacity market uses a vertical demand curve and procures resources one year in advance. PJM’s mandatory market uses a sloped demand curve and obtains capacity three years ahead of delivery.
MISO has only conducted two auctions so far, for 2013/2014 and 2014/2015. The clearing price for the zone, including Dynegy’s Illinois generation, was $16.75/MW-day for the 2014/2015 delivery year. The PJM clearing price for the same period was $125.99/MW-day.
Critics say MISO’s construct makes it hard to attract capital investment and that its vertical demand curve causes excessive price volatility.
Among the critics is MISO’s Independent Market Monitor, whose 2013 State of the Market Report cited as flaws the vertical demand curve, “barriers to capacity trading with PJM and barriers to participation in the auction affecting units with suspension or retirement plans impacting the planning year.
“MISO’s economic signals in 2013 would not support private investment in new resources, which is partly due to the modest capacity surplus that currently exists in MISO,” the report said. “However, we believe the economic signals would continue to be inadequate even under little or no surplus because of the shortcomings of MISO’s current capacity market.”
The IMM said MISO’s 2013 replacement of its Voluntary Capacity Auction (VCA) with an annual Planning Reserve Auction (PRA) didn’t go far enough. “Though an improvement, the PRA continues to reflect a poor representation of the demand for capacity [or planning reserves], which undermines its ability to provide efficient economic signals.
“It will be critical to address these issues in the near future because increased retirements and capacity exports are projected to generate a capacity deficiency as soon as 2016. Improving the performance of the capacity market may play a pivotal role in ensuring that MISO will continue to have access to sufficient capacity.”
What Dynegy Has at Stake
Dynegy currently has about 13,200 MW of generation, including 7,042 in MISO from five coal-fired plants it bought from Ameren last year.
Only Exelon, with its nuclear fleet of more than 11,000 MW, has more generation than Dynegy in Illinois.
Dynegy, which currently has 1,780 MW in PJM, would gain about 9,000 MW in the RTO if it wins approval for deals announced last month to purchase generation from Duke Energy and Energy Capital Partners. About 2,500 MW of that would be in Illinois’ PJM region.
MISO’s share of Dynegy’s total generation will fall to 29% from 53% as a result of the expansion in PJM and New England. But Dynegy CEO Robert Flexon said he was counting on Dynegy’s participation in MISO to be a plus for the company. The next several years, he said, “should be a really peak time for the MISO marketplace” due to plant retirements.
No filings have been made with the Federal Energy Regulatory Commission.
MISO declined comment when asked about Dynegy’s suggestion that it may leave the RTO. The Illinois Commerce Commission also declined to comment.
PJM spokesman Ray Dotter said the RTO “does not comment on the market positions and plans of individual members. We cannot speculate on Dynegy’s reported plans.”
Exelon, which has one nuclear generating station — the 1,078-MW Clinton Power Station — in MISO, has said in the past that Clinton’s economic viability is limited in part by MISO market rules.
“We agree that the MISO capacity market needs to be improved to protect the reliability of the system for Illinois electric consumers and the state’s economy,” the company said in a statement. “We have not seen Dynegy’s proposal and cannot comment on it.”
ComEd’s Departure
It wouldn’t be the first time companies switched from one RTO to another.
In 2002, Commonwealth Edison, and its parent company, Exelon, asked FERC for permission to leave MISO and join PJM. The move came after it was unable to reach agreement on new rate structures with MISO.
Exelon said most of its wholesale trading partners and suppliers and its strongest interconnections were to the east of ComEd. The integration was completed in 2004.
ComEd’s PJM zone was initially an island, separated from the rest of the RTO to the east, until American Electric Power and Dayton Power and Light joined later that year. Since then, Duquesne Light, Dominion Virginia Power and FirstEnergy in Ohio have also joined PJM.
To leave one RTO and join another could involve several steps, including showing that negotiations with the current RTO had been unsuccessful. Affected state regulatory agencies, in this case the ICC, could choose to intervene in the FERC case on one side or the other.
Dynegy is also eyeing other markets. In an interview last week with the Houston Business Journal, Flexon said that the portfolio of Energy Future Holdings — parent company of power generator Luminant, TXU Electric and transmission company Oncor — might be a nice addition to Dynegy’s growing portfolio. Energy Future Holdings’ operations are in the ERCOT market in Texas, and the company is going through bankruptcy proceedings now.
Although Dynegy’s headquarters is in Houston, it has no operations at all in Texas since emerging from its own bankruptcy. “If there ever were portfolios for sale in Texas, that could one day be something that Dynegy would have an interest in,” Flexon said.
“We want to operate in well-functioning markets, and that is what we are looking to do,” Dynegy’s Sullivan said.
Market Monitor Joe Bowring and stakeholders representing load expressed doubts last week about PJM’s latest capacity market proposals, questioning the cost and need for what Bowring called a “dramatic redesign” of the market.
The RTO last month proposed the creation of a Capacity Performance product that would supplement the existing Annual Capacity offering. In a late afternoon meeting Wednesday, Bowring said he was “very skeptical of the multi-product proposal,” echoing other stakeholders in saying it could encourage withholding by generators.
Parameter Changes Opposed
The meeting coincided with PJM’s release of stakeholder letters urging the Board of Managers not to act on PJM staff’s proposed changes to capacity auction parameters. Stakeholders representing load interests said the board shouldn’t consider staff’s proposed changes in the shape and position of the capacity demand curve — which failed to win stakeholder consensus last month — until it evaluates how they would interact with PJM’s new product proposal.
PJM’s proposals come as the capacity market is still digesting changes implemented in May’s Base Residual Auction, when prices in most of the RTO doubled following limits on the role of imports and demand response.
The Southern Maryland Electric Cooperative called Capacity Performance “the most material changes to PJM markets since the advent of [the Reliability Pricing Mechanism] itself.” Regulators from Maryland and Illinois said the proposal means “fundamental changes to the very nature of the capacity product.”
The “Load Coalition,” a group of 17 stakeholders, including regulators and load-serving entities, said that “load must never be viewed by the PJM board as offering a blank check.”
The letters served as a preview of the arguments the stakeholders would likely make if the board seeks the Federal Energy Regulatory Commission’s approval of staff’s proposed changes.
Old Dominion Electric Cooperative noted that members participating in the Triennial Review of capacity market parameters failed to reach consensus on changes to the demand curve, the calculation of the cost of new entry (CONE) or the cost of capital.
“Dispute over any one of these components will be contentious and polarizing at FERC. All three together could be paralyzing and will distract from other priority PJM initiatives,” ODEC said.
In all, regulators or public advocates for seven of PJM’s 13 states and D.C. weighed in against the parameter changes. Also expressing opposition as members of the Load Coalition were American Municipal Power; Blue Ridge Power Agency; Duquesne Light; North Carolina Electric Membership Corp.; Rockland Electric; the Public Power Association of New Jersey; the American Public Power Association; and the PJM Industrial Customer Coalition.
Dynegy also raised objections.
The board received only two letters in favor of the changes, one from the PJM Power Providers Group and another from American Electric Power, Dayton Power and Light and FirstEnergy Service Co. They supported the proposed changes to the variable resource requirement curve but said PJM staff’s 8% after-tax weighted average cost of capital is too low.
Monitor’s Meeting
Wednesday’s meeting was scheduled to discuss the Monitor’s analysis of the 2017/18 Base Residual Auction in May. The Monitor’s report, released in July, concluded that PJM capacity prices would increase sharply but reliability would not be threatened if a recent federal court ruling eliminated demand response from wholesale markets. The report also evaluated how prices would have been affected had other changes favored by the Monitor been enacted. (See Life without Demand Response: Higher Prices but No Reliability Crisis, Says Monitor.)
Bowring told attendees he hopes to release sensitivity analyses of PJM’s Capacity Performance proposal as soon as this week. Bowring said his office is discussing the analyses with PJM to ensure the assumptions are valid and that the results don’t violate confidentiality rules.
“We want to have some meaningful results,” Bowring said. “We don’t want to make [unreasonable] assumptions.”
Bowring said that the PJM proposal had “a lot of positives,” citing staff’s call for heightened performance incentives and penalties. “Leaning heavily on the performance incentives makes sense,” Bowring said.
Jim Benchek of FirstEnergy questioned how market power would be mitigated under the PJM proposal. “That’s a part that’s been left a mystery to us,” he said.
ODEC’s Ed Tatum asked Bowring to compare the costs of PJM’s proposal to the $600 million in uplift in January, saying the PJM proposal might cost ratepayers more than it saves.
Citigroup’s Barry Trayers expressed a similar concern, saying PJM’s changes may be an overreaction to a “once-in-20-year” winter, noting that PJM typically has a 30% reserve margin during the cold months.
Bowring said he shared concerns about overreacting to last January, when as much as 22% of PJM’s generation suffered forced outages. At the same time, he reiterated his contention that capacity prices have been improperly suppressed by the role of Limited and Extended Summer demand response.
At the Operating Committee meeting last week, several members expressed concern about including new rules regarding gas unit commitment as part of the Capacity Performance filing with FERC.
Dave Pratzon of GT Power Group said there wasn’t enough time to reach consensus on the gas rules and that their inclusion could lead to more adversarial proceedings before FERC.
John Farber of the Delaware Public Service Commission agreed. “To try to force this into the same filing, I think a lot would be lost,” he said.
Auction Parameters and Capacity Performance
Members deadlocked last month on changes to capacity market parameters, with none of five proposals resulting from the FERC-ordered Triennial Review winning a supermajority at the Markets and Reliability Committee. (See Members Deadlock on Capacity Parameter Changes.)
As a result, the Board of Managers will decide for itself whether to seek FERC approval for PJM staff’s proposed changes. The board also is expected to decide unilaterally whether to seek FERC approval for staff’s Capacity Performance proposal under the never-before-invoked Enhanced Liaison Committee process. PJM officials said they initiated the Liaison process because they did not expect stakeholders to reach consensus.
In their letters, load representatives said changing the auction parameters and introducing the new capacity product could cause unreasonable increases in capacity costs. Maryland and Illinois regulators said the proposed parameter changes could increase capacity costs by $1.5 billion annually.
“In the Capacity Performance discussions with PJM staff last month, PJM indicated that 140,000 MW of resources are potentially compliant with the requirements of being a Capacity Performance resource, meaning that the clearing price required of those resources which are not compliant will create a windfall for the remaining compliant resources,” SMECO said. “By creating two classes of annual capacity products, the potential for the exercise of market power in the supply curve of Capacity Performance resources is only exacerbated by the changed VRR curve shape proposed by PJM.”
The Load Coalition said the board should defer action on the capacity parameters for which there is no consensus “so the board may ensure the interrelated parts of RPM work together appropriately to satisfy the applicable reliability standards while still honoring the Federal Power Act’s ‘just and reasonable rates’ standard.”
The coalition challenged PJM staff’s contention that the parameter changes and Capacity Performance initiative are “separate and distinct.”
The coalition noted that PJM asked FERC to defer action on its Section 206 proceeding on replacement capacity — PJM’s effort to reduce arbitrage opportunities in incremental capacity auctions — pending the Capacity Performance filing.
“The Load Coalition views the Triennial Review to be at least as closely linked, if not more so, with the Capacity Performance initiative than the Replacement Capacity effort may be, particularly because PJM’s proposed VRR curve shape has been shown individually by PJM’s own simulations to procure capacity materially beyond what would be required to meet our resource adequacy objectives,” the coalition said.
Based on the modeling assumptions of PJM’s consultant, the coalition said the parameter changes would result in a Loss-of-Load Expectation of one load shed event in 16.7 years — far above PJM’s 1-in-10 LOLE standard. The coalition said the consultant’s assumptions “greatly overstate volatility and reliability risk.”
“As virtually captive customers to the PJM markets, load must never be viewed by the PJM board as offering a blank check. With the close nexus between energy markets and economic growth, the PJM board has a serious responsibility to ensure not only reliable operations but also rates that are just and reasonable and not unduly discriminatory, as the Federal Power Act requires.”
The Maryland and Illinois commissions said the Capacity Performance initiative and the possible elimination of the $1,000 Offer Bid Cap in the energy market could add to the increased costs resulting from the parameter changes.
“The commissions believe it is important to evaluate these measures together rather than a piecemeal fashion so that a full understanding of all of the implications of these changes upon PJM’s capacity market can be achieved. Changes to RPM have often had unintended outcomes; a process that does not fully evaluate proposed changes jointly will do nothing to minimize the occurrence of such unintended outcomes.”
The P3 Group said the board should seek FERC approval of the demand curve changes without delay, saying they are necessary to “enhance the long-run performance of the curve, ultimately improving auction outcomes and supporting long-run reliability.”
“The purpose of the Triennial Review is distinct from the Capacity Performance proposal. The components of the Triennial Review work to establish the volume of procured capacity to meet resource adequacy standards. In contrast, the capacity performance proposal describes the attributes of the capacity commitment. Further, the outcome of the capacity performance proposal is uncertain. Its uncertainty should not cloud the completion of the Triennial Review.”
