Five years in the making, the Federal Energy Regulatory Commission has developed a comprehensive scorecard for comparing the performance of RTOs and ISOs, as well as utilities outside of organized markets.
FERC identified 30 common performance metrics tracking everything from system reliability to generator revenues and RTO administrative costs.
How well did PJM do?
The report, which covers 2006-2010, found that PJM lagged among its peers in wind forecasting accuracy, forced outage rates and congestion costs, but that the RTO excelled in generator interconnection processing, administrative costs and customer satisfaction.
Among the other metrics tracked are load forecasting accuracy, demand response participation, system lambda, net generation revenues and LMPs. The report also documented big disparities in the costs of feasibility, system impact and facility studies.
FERC Chairman Cheryl LaFleur said the report reflects “a desire to understand what drives success [in RTOs]. What’s that saying? If you can’t measure, you can’t manage.”
FERC staff is seeking public comment on the metrics and approval from the Office of Management and Budget to replicate the data collection for years after 2010.
The Federal Energy Regulatory Commission rejected an agreement between Duke Energy Carolinas and Duke Energy Progress to share capacity, saying the deal would be discriminatory.
The two companies, subsidiaries of Duke Energy following its acquisition of Progress Energy, said they created the capacity agreement to provide savings to their native load customers in North and South Carolina.
The agreement would allow the companies to “make temporarily excess capacity available to each other for time periods when” one party “is projected to have more capacity than is required” to meet reliability standards.
The companies said the capacity agreement would allow them to minimize purchases of capacity and “commitment of additional generation.”
The companies also said the sharing would be done “for no additional monetary compensation” because of the reciprocal nature of the agreement.
FERC was not persuaded. “Applicants have failed to demonstrate how sharing capacity with an affiliate at a zero-price term to the exclusion of other parties is just and reasonable and not unduly discriminatory or preferential under [Federal Power Act] section 205,” the commission ruled (ER14-2356).
The ruling does not affect the companies’ agreement to share economic dispatch of their owned and purchased generating resources.
Duke Energy, Dominion Resources and other partners last week proposed a 550-mile, $5 billion pipeline to carry natural gas from the Marcellus and Utica shale formations to Virginia and eastern North Carolina.
The “Atlantic Coast Pipeline” would carry 1.5 billion cubic feet of gas per day.
Originally, the pipeline was solely a Dominion project. The company announced its intention to build what was then called the Dominion Southeast Reliability Project earlier this year.
Separate from Dominion’s project, Duke and Piedmont Natural Gas solicited proposals in April to bring natural gas into North Carolina. Now Duke, Piedmont and AGL Resources have agreed to join together with Dominion.
Duke will own 40% of the pipeline. Dominion, Piedmont and AGL will own 45%, 10% and 5% respectively.
Six utilities — Duke Energy Carolinas, Duke Energy Progress, Virginia Power Services Energy, Piedmont Natural Gas, Virginia Natural Gas and PSNC Energy — will buy the majority of the pipeline’s capacity in 20-year contracts.
Dominion, which will oversee construction and operation, said it expects to seek FERC approval by 2016. The partnership said it could be in operation by late 2018.
Duke found itself in need of additional sources of gas following its acquisition of Progress Energy and its efforts to reduce its reliance on coal-fired generation. It closed half of its 14 coal-fired plants in the past three years, built five gas-fired plants in North Carolina since 2011 and plans on building another gas-fired plant in South Carolina.
Historically, the Southeast has received natural gas from wells in Louisiana, Oklahoma and Texas. Supply problems and other constraints have sometimes driven gas prices up.
The boom in shale gas production meant the emergence of a northern source of low-priced fuel. The Atlantic Coast Pipeline is the first project designed to deliver those supplies to Virginia and North Carolina. The pipeline will carry gas from the shale fields in Pennsylvania, Ohio and West Virginia.
Dominion says it has already reached agreements with about 70% of the landowners on the route to allow them to survey.
While the partners and elected officials applauded the announcement — Virginia Gov. Terry McAuliffe called it a “game changer” for industry and residential customers — environmentalists are less than enthused.
“Today Gov. McAuliffe has made a huge mistake that harms the environment,” said Mike Tidwell, executive director of the Chesapeake Climate Action Network. “Barely two months after re-launching the state’s climate change commission, the governor has regretfully embraced a Dominion gas pipeline project that threatens to contribute significantly to the climate crisis.”
Tidwell said the pipeline will encourage more fracking and contribute to methane emissions.
“There is enormous leakage from the fracking process, and enormous leakage from the distribution pipelines, where it gets off the main pipeline,” he said Friday. “It gets down to the municipals and the counties, and [those pipelines] are all old and they’re leaking like sieves.”
The Federal Energy Regulatory Commission last week ordered a review of PJM’s rules regarding up-to-congestion transactions (UTCs), saying the RTO may be discriminating in how it treats these and other financial trades.
FERC’s ruling (EL14-37) came in response to a PJM filing in June defining UTCs as virtual trades and seeking to subject them to the RTO’s Financial Transmission Rights (FTR) forfeiture rule. (See MRC Defines UTCs; Adds Bid Limit and FTR Forfeiture Rule.)
The commission ordered a Section 206 proceeding to determine whether PJM is improperly treating UTCs differently than increment offers and decrement bids in the interpretation of the forfeiture rule and in the application of uplift charges. It ordered FERC staff to schedule a technical conference on the issue.
PJM’s filing sought to apply the FTR forfeiture — previously applied only to INCs and DECs — to UTCs. The rule is intended to prevent traders from submitting UTCs that boost the value of their FTR. It is applied when those UTCs result in a higher LMP spread in the day-ahead market than in the real-time market.
PJM’s Market Monitor told FERC that PJM’s method for applying the rule to UTCs is inconsistent with how the RTO treats INCs and DECs because it relies upon the contract path, rather than modeled flows.
Trading in UTCs has increased eight-fold since 2010, while INC and DEC trading has dropped by two-thirds. The shift occurred after PJM removed the requirement that UTCs make transmission service reservations.
“The recent growth in UTC transactions, and the corresponding decrease in other virtual transactions, strongly suggests that many UTC transactions may be used in place of virtual transactions. To the extent that a UTC transaction is simply the combination of two virtual transactions that have been connected, it may not be appropriate to treat UTC transactions differently than INCs and DECs in applying the FTR forfeiture rule,” the commission wrote.
“For instance, where a UTC is submitted in combination with INCs and/or DECs and the associated flows on the constrained paths of the combined transaction may be different from those assumed when considering the transactions individually, the tariff may not protect against manipulative transactions.”
The commission also said the forfeiture rule “does not consider trading of INCs/DECs and UTC transactions for the purpose of preventing congestion in order to benefit a short FTR position.”
The commission said it expects to rule on the matter within five months after submission of post-technical conference pleadings. Any refunds resulting from the review will be effective from yesterday, when the notice of the 206 proceeding was published in the Federal Register.
Attorney Ruta Skucas, who represents the Financial Marketers Coalition, said UTC trading volumes will likely drop while the case is pending.
“There will be potentially months of uncertainty” for UTC traders who don’t know if they will be assessed uplift charges, she said in an interview.
PJM’s Market Monitor overstepped its authority in calculating the maximum price generators can offer into capacity auctions, but the RTO’s Tariff may need to be changed to prevent a windfall to generators, the Federal Energy Regulatory Commission ruled.
The commission ruled in favor of FirstEnergy Solution’s challenge to the Monitor’s method of calculating market seller offer caps. But while FE won its legal argument, the commission also gave weight to arguments by the Monitor and load representatives, who contended FE’s interpretation could allow generators to exercise market power. As a result, the commission ordered a “paper hearing” to determine whether PJM’s Tariff should be changed.
In April, FE asked FERC to rule that PJM’s Tariff requires the use of a generator’s cost-based energy offers in the determination of net projected PJM market revenues, a component used in calculating capacity offer caps.
The Monitor uses the lower of the price-based offer and the cost-based offer submitted by the capacity resource.
The case centered on a dispute over the Tariff’s requirement that projected energy market and ancillary services revenues be “net of marginal costs for providing such energy (i.e., costs allowed under cost-based offers pursuant to Section 6.4 of Schedule 1 of the Operating Agreement) and ancillary services.”
FERC agreed with FE that the Tariff’s use of the abbreviation “i.e.” prevents the Monitor from exercising its discretion in choosing between price- and cost-based offers.
“The term ‘i.e.,’ as defined by Black’s Law Dictionary, is an abbreviation of the Latin id est meaning ‘that is.’ The Tariff therefore is defining the term ‘marginal costs’ to be the cost-based offers under Section 6.4 of Schedule 1,” the commission ruled (EL14-36). “In addition, the Tariff neither mentions a ‘lower-of’ methodology as proposed, nor does it suggest that the determination of marginal cost is subject to the interpretation of the IMM. Indeed, the final interpretation is made by PJM under the Tariff, and our interpretation is also consistent with PJM’s own reading of its Tariff.”
The Monitor said its interpretation was justified because non-zero price-based energy offers that are less than cost-based offers reflect actual marginal cost. Intervenors representing consumers had filed comments supporting the Monitor’s position.
The PJM Industrial Customer Coalition and consumer advocates for six states and D.C. contended a FE victory “would result in a direct transfer of potentially billions of dollars from customers to sellers.” (See Billions at Stake in Capacity Market Challenge.)
Because of those concerns, the commission said, the Tariff’s provisions for the calculation of projected market revenues “may be unjust and unreasonable.”
The commission ordered PJM to file a brief defending the current language within 60 days. Reply briefs will be due 30 days after PJM’s brief.
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.
Five years in the making, the Federal Energy Regulatory Commission has developed a comprehensive scorecard for comparing the performance of RTOs and ISOs, as well as utilities outside of organized markets.
Among the other metrics tracked are load forecasting accuracy, demand response participation, system lambda, net generation revenues and LMPs. The report also documented big disparities in the costs of feasibility, system impact and facility studies.
FERC Chairman Cheryl LaFleur said the report reflects “a desire to understand what drives success [in RTOs]. What’s that saying? If you can’t measure, you can’t manage.”
