A subsidiary of NRG Energy announced late last week that it will buy the largest wind farm in North America for $870 million. The deal is seen as another move by NRG to bulk up its portfolio of renewable energy, especially important now that the Environmental Protection Agency has issued its carbon emission reduction rules.
NRG Yield Inc. is buying California’s 947-MW Alta Wind Energy Center. NRG formed NRG Yield in December 2012 to own and operate its “clean energy” fleet. The project is located in Tehachapi Pass in California’s Kern County and sells its power under long-term power contracts with Edison International.
The Nuclear Regulatory Commission began a surprise inspection last week at Dominion’s Millstone nuclear generating station in Waterford, Conn., after both units shut down unexpectedly May 25. Millstone Units 2 and 3 shut down safely after a problem at one of three off-site high-voltage lines that feed power to the plant.
Unit 2 shut down without complications. At Unit 3, however, several problems arose during the shutdown, including a problem with a reactor coolant system drain. The inspection of both units started last week. There is no word on how long the inspection will take. The NRC said it will issue a report 45 days after the end of the inspection.
PPL Corp and Riverstone Holdings LLC said yesterday they would combine their generation businesses into a new publicly traded independent power producer.
The new company will be called Talen Energy Corp. and will own and operate 15,320 MW of capacity. Talen will be listed on the New York Stock Exchange, with PPL shareholders owning 65% of the company and Riverstone owning 35%. Financial terms of the deal were not disclosed.
The Wall Street Journal reported last week that Dynegy is among those bidding for Duke Energy’s 11 fossil fuel-fired plants in the Midwest, going up against Blackstone Group and Riverstone Holdings. Citing unnamed sources, the Journal said that Dynegy, less than two years from emerging from bankruptcy, is looking increase its customer base. The plants, in Ohio, Illinois and Pennsylvania, are expected to sell for about $2.5 billion.
Leading Republicans on the Senate Energy and Natural Resources Committee said last week they remain skeptical of President Obama’s nomination of Norman Bay to chair the Federal Energy Regulatory Commission.
Cheryl LaFleur and Norman Bay being sworn in to the Senate hearing.
Their comments came after the release of Bay’s and acting FERC Chair Cheryl LaFleur’s responses to written questions posed by the committee following their confirmation hearing May 20.
“Even though Senator Barrasso doesn’t always agree with Ms. LaFleur’s policy positions, he believes she is unquestionably qualified for her position. That’s why at the nomination hearing, he asked why the Senate should demote Ms. LaFleur to make room for Mr. Bay,” said Laura M. Mengelkamp, press secretary for Sen. John Barrasso (R-Wyo.). “Senator Barrasso continues to have concerns about Mr. Bay’s qualifications for the commission. His written responses following his nomination hearing raise more questions than answers.”
Robert Dillon, communications director for ranking member Lisa Murkowski (R-Alaska), said the senator also remains unconvinced that Bay is qualified to lead FERC and would prefer to see LaFleur remain chair.
“Don’t mistake us for loving LaFleur,” Dillon said. “We think she’s fair. We think she’s qualified. But she’s not a Republican.”
Among the questions Murkowski posed was whether Bay would accept a position on the commission if LaFleur remained chair.
Bay said he didn’t know whether he would have accepted the nomination if the president had not offered him the chairmanship. “It would not be appropriate for me to speculate on what I would do if I were designated for a position other than what the president has indicated,” he said.
No Horse Trading
“Senator Murkowski’s not dangling something out there as a proposal,” Dillon said, noting that Democrats outnumber Republicans on the panel 12-10. “There’s no horse trading going on. We don’t have the horses to trade.”
But he added, “Maybe the president and the Democrats will decide on their own it doesn’t look good to demote Cheryl LaFleur.”
Bay needs 12 votes to clear the committee and proceed to a floor vote. If Republicans remain united in opposition, the loss of one Democrat would result in an 11-11 tie, sinking his chances.
Last year, West Virginia Democrat Joe Manchin killed the nomination of President Obama’s first choice, former Colorado regulator Ron Binz, whom he portrayed as anti-coal. Although Manchin has not accused Bay of being a soldier in the “war on coal,” he joined the Republicans in questioning his qualifications for the chairmanship.
Manchin prefaced one post-hearing question with the assertion that Bay had “no direct experience in regulation of energy infrastructure or markets.”
“The previous five chairmen all had more than 20 years of experience in the energy industry and as regulators before becoming chairman,” Manchin continued.
Defends Policy Experience
Bay rejected Manchin’s predicate, citing his five years as the director of FERC’s Office of Enforcement (OE).
“As one of the 11 office directors, I participate in weekly meetings with the chairman and other office directors on a wide array of important issues,” Bay said. “OE has a broad portfolio that requires a deep understanding of the markets, including market rules and market fundamentals.”
While Bay — like LaFleur — was careful to avoid taking definitive stands on controversial issues, his answers did demonstrate a familiarity with a broad range of topics beyond enforcement, including Standard Market Design, capacity markets, qualifying facilities, Order 1000, returns on equity, smart grid and liquefied natural gas.
As at the hearing, many of the questions followed the script of former FERC general counsel William Scherman and other critics of FERC’s enforcement policies.
Enforcement Policy
Scherman’s critique was laid out in detail in an article in The Energy Law Journal, and summarized in an op-ed in The Wall Street Journal, days before Bay’s confirmation hearing.
In his written responses, Bay provided a more forceful rebuttal than he mounted during the in-person questioning.
Bay said the law journal article “confused SEC administrative hearing and investigation rules; failed to describe FERC’s actual investigation process and the significant transparency provided in that process; failed to discuss the significant transparency, guidance and analysis of how the Commission has implemented and applied Congress’s prohibition against market manipulation in FERC-jurisdictional markets; made various statements of law for which they provided no legal authority; and numerous other errors and unsupported assertions.”
“If confirmed, I would be open to considering how FERC can improve the way it does its work and always willing to listen to market participants who have constructive suggestions,” Bay continued. “But this article’s allegations of due process and substantive violations in FERC enforcement, and the analysis underlying those assertions, are wide of the mark.” (See related story, LaFleur Parts with Bay on Enforcement Procedures.)
No date has been set for a committee vote on the nominations, said Dillon, who noted the Senate has 150 other nominations pending on the floor.
“There is really no reason to rush this one through,” he said. “[Senate Majority Leader] Harry Reid has his hands full.”
Calpine Corp. led Gov. Jack Markell and Environmental Protection Agency Secretary Gina McCarthy on a tour of its under-construction Garrison Energy Center in Dover last week. “This project is putting people to work and will bring the cost of energy down,” Markell commented after the tour of the $400 million combined-cycle plant. “What is there to argue about?” Calpine expects to expand the plant to eventually produce 618 MW of power with the first 309 MW scheduled to go on line in mid-2015.
The General Assembly passed a bill that frees up $30 million in existing state funds for renewable energy generation investment. House Bill 2427 calls for the money, which comes from the Renewable Energy Resources Fund, to be used for distributed solar generation projects with less than 2 MW of capacity. The money is to be administered by the Illinois Power Agency, which has so far committed only $3 million of the existing $54 million in the fund. HB 2427 sets out new procedures calling for IPA to commit the $30 million on solar projects by June 2015.
Indiana Attorney General Greg Zoeller has decided to stop pursuing criminal charges against the former head of the Utility Regulatory Commission after a state trial court judge dismissed the charges. Zoeller said it was unlikely an appeal would be successful.
David Lott Hardy was fired in 2010 and indicted on official misconduct charges in 2011 for allowing the commission’s lead attorney to continue to work on cases involving Duke Energy even after he knew the lawyer was seeking a job with the utility.
The judge dismissed the case after the legislature amended the official misconduct statute to exclude the conduct Hardy was accused of from being considered a criminal act.
State Erred in Killing Program, Watchdog Group Says
A consumer watchdog group said that lawmakers were “short-sighted” when they killed the state’s fledgling Energizing Indiana program at the end of last year without funding a replacement.
The energy-efficiency program could have helped Indiana meet the new Environmental Protection Agency carbon emission limits, according to Citizen’s Action Coalition Executive Director Kerwin Olson. “We kind of shot ourselves in the foot here in Indiana by eliminating these programs,” he said. “It was a short-sighted decision and more so now that we’ve seen these carbon rules that would allow efficiency programs to be used as a tool to meet these goals.”
Bathymetry (underwater depth) survey of the Maryland-Delaware coast, with Wind Energy Area outlined. (Source: Maryland Energy Administration)
A high-definition oceanographic and geophysical survey of Maryland’s Wind Energy Area, expected to be crucial for the development of offshore wind projects off Maryland, was released last week by the Maryland Energy Administration. The survey, which mapped the seafloor geology of the state’s designated Wind Energy Area, is thought to be the first such mapping done by any state in the U.S. The engineering firm contracted to do the study plotted depth, seafloor conditions and seabed geology, and looked for shipwrecks. “The data we are making available will reduce the risks and costs of offshore wind energy developments, protect the marine environment and contribute to our scientific understanding of the oceans off our coast,” MEA Director Abigail Ross Hopper said.
The U.S. Court of Appeals in Richmond last week upheld an earlier federal court ruling prohibiting Maryland from subsidizing new power plants in the state, saying Maryland’s proposed plan would usurp the Federal Energy Regulatory Commission’s authority over interstate power rates.
The ruling invalidates the Maryland Public Service Commission’s April 2012 order directing Baltimore Gas and Electric Co., Potomac Electric Power Co. and Delmarva Power & Light Co. to enter into contracts that guaranteed CPV Maryland LLC an income stream so that it could finance construction of the Charles County facility. PPL Corp., PSEG Power LLC and Essential Power LLC were the plaintiffs against Maryland.
“A wealth of case law confirms FERC’s exclusive power to regulate wholesale sales of energy in interstate commerce, including the justness and reasonableness of the rates charged,” the court said. “Maryland has sought to achieve through the backdoor of its own regulatory process what it could not achieve through the front door of FERC proceedings.”
The state Attorney General’s office last week charged Chesapeake Energy Corp. with felony fraud charges, saying Chesapeake leasing agents conned land owners out of the ability to seek competing bids for oil and gas leases in 2012. The state earlier charged the company with engaging in a bid-rigging conspiracy with another energy company to keep lease prices artificially low during a 2010 auction.
“I will defend and protect the taxpayers of Michigan in the face of fraudulent business practices,” Attorney General Bill Schuette said in a news release. “Scamming hardworking Michigan citizens is not how we do business in this state.” Last month, the other company involved in the bid-rigging case with Chesapeake, Encana Corp., agreed to pay a $5 million fine and cooperate with authorities in the ongoing case with Chesapeake.
Chesapeake spokesman Gordon Pennoyer called the new charges “baseless allegations.”
The Lansing Board of Water and Light, a publicly owned utility, announced last week that it intends to build a 5-MW solar facility that would be the largest solar energy project in the state. The board said it will be seeking bids to start the project. Currently, the board receives 6% of its electricity from renewable sources. The solar project will help it reach the state’s goal of getting 10% of electricity from renewable sources by 2015, the board said.
The Board of Public Utilities last week sued three third-party energy providers – Palmco Power, HIKO Energy and Systrum Energy – for alleged fraudulent practices. “These three companies allegedly lured consumers with promised monthly savings that turned out to be fictional,” Acting Attorney General John J. Hoffman said. “Even worse, consumers who hoped to save money instead saw their bills increase to unconscionable levels.”
The commission alleges that all three companies approached customers with misrepresentations about “competitive” monthly pricing or guaranteed reductions if they switched from traditional suppliers, and then charged far more than customers had been paying, in some cases up to 300% more. The state also accused Palmco and HIKO of switching customer gas or electric accounts without the consumers’ knowledge.
The Board of Public Utilities last week approved a 2.6% rate cut for Atlantic City Electric customers. In its annual rate review, the utility sought to adjust several pass-through charges, including the non-utility generation charge, societal benefits charge and system control charge. An average residential user using 1,000 kWh should see a savings of about $4.55 in the next billing cycle.
The Board of Public Utilities deferred action on a petition by the Sierra Club calling on New Jersey to increase efforts to promote energy-efficiency projects. The BPU said it wanted to await the results of several working groups already set up to investigate energy-use reduction by residential and business customers before acting on the petition. “I do not believe it’s necessary to do it at the present time,” BPU President Diane Solomon said.
The Sierra Club of New Jersey wants the state to adopt an energy-efficiency portfolio, similar to a renewable energy portfolio, saying New Jersey is falling behind other states in efforts to promote energy efficiency.
“They all say they support this, but then nothing happens,” complained Jeff Tittell, New Jersey Sierra Club director. “How long are we going to lag behind? The board really does not want to do anything.”
An Arizona company has filed with the Orange County Board of Commissioners for permits to build a 4-MW solar farm near Hillsborough, north of Chapel Hill. The North Carolina Utilities Commission has already approved the company’s plan for a solar facility on the 50-acre property.
But some area residents question the effect Sunlight Partners’ project would have on the rural area. “This facility, with its 18,000 panels over 20 acres, will permanently transform what is one of the most bucolic and tranquil residential neighborhoods in the county into what amounts to an industrial zone,” neighbor Bob Cantwell said. Sunlight Partners, founded in 2010, has 48 potential North Carolina sites under consideration, company officials said.
Gov. Pat McCrory signed a bill last week lifting a 2012 moratorium on hydraulic fracturing. “The expansion of our energy sector will not come at a cost to our precious environment,” McCrory said after signing the Energy Modernization Bill last week. “This legislation has the safeguards to protect the high quality of the life we cherish.”
Critics disagreed. “There are more than 1,000 documented cases of contaminated water from fracking across the country,” Environment North Carolina Director Elizabeth Ouzts said. “By rushing to frack, Gov. McCrory and legislative leaders are putting North Carolina’s rivers and the drinking water for millions in jeopardy.”
North Carolina legislators are pushing for inclusion of firm deadlines in a proposed law that would require Duke Energy to stop unlined coal ash dumps from leaching pollution into waterways. Gov. Pat McCrory introduced legislation in May that would require Duke to clean up four ash dumps but allow the company and state environmental officials to set the timeline.
The ash cleanup project was spurred by a giant ash spill on the Dan River earlier this year. Duke continues to spend millions cleaning up that spill. “The public, the people we represent, the people we serve here in the legislature across North Carolina, they want to see some specific timetables,” said Sen. Gene McLaurin (D-Richmond).
A week after the Environmental Protection Agency issued rules calling on states to reduce greenhouse gas reductions, Gov. John Kasich is expected to sign a bill freezing renewable energy standards for two years. Senate Bill 301 was backed by Republicans as a way for Ohio to review standards and their effects on the state’s economy.
“The purpose of the study committee is to determine what standards are economically reasonable and to promote job creation and economic growth in Ohio,” a spokesman for state Senate Republicans said. Backers of green energy think the bill will be a barrier to complying with the new EPA carbon emission rules.
A bipartisan bill asking the state Environmental Protection Agency to come up with a strategy to meet the new EPA carbon emissions standards was introduced in the Ohio House. Sponsored by Republican Rep. Andy Thompson and Democrat Rep. Jack Cera, the bill attempts to minimize the impact of the federal EPA rules while complying with them. Thompson said the bill specifically eyes the use of coal as an energy source. “Why would we eliminate that as part of our portfolio?” he asked. “Let’s continue to look for ways to make it cleaner but let’s not just discard it.”
The Public Utility Commission last week voted to fine Pennsylvania Gas & Electric $150,200 in a settlement for alleged “slamming” incidents by a company vendor. An investigation by the commission alleged that the vendor switched the electric and natural gas accounts of 309 large commercial customers without their authorization. The investigation began after the commission received complaints about the company’s marketing practices. It concluded that one telephone sales representative circumvented quality controls of the company’s sales system.
“PaG&E did not appear to have any internal controls in place to prevent the volume of slamming that allegedly occurred here,” the commission report said. “We have said many times that this commission will not tolerate behavior that erodes the public trust in Pennsylvania’s retail energy markets.” The commission is accepting public comment before finalizing the settlement.
PUC Appoints Director of Competitive Market Oversight
The Public Utility Commission last week appointed a 30-year member of the agency as its new director of the Office of Competitive Market Oversight. H. Kirk House will report to the commission’s executive director on retail competitive electric and gas markets.
The commission also appointed Daniel J. Mumford as deputy director. House was previously lead counsel with the commission’s Office of Special Assistants and worked in all areas of regulatory oversight. Mumford comes to the position after 24 years with the commission’s Bureau of Consumer Services.
Exelon Funding Dam Removal Projects as Part of License Bid
Muddy Run (Source: Exelon)
Exelon Generation, operator of the Muddy Run Pumped Storage Facility on the Susquehanna River, is providing the Pennsylvania Fish and Boat Commission with $800,000, which will be used to remove small dams in the lower Susquehanna River Basin. The dam removal projects will improve water quality and allow migratory eels and American shad to move up and down the river, according to the commission.
The money is part of the company’s remediation efforts for the pumped storage facility, which is located upstream from the company’s Conowingo Dam. Exelon is providing the money as part of its relicensing efforts for Muddy Run. The commission said there are several hundred small dams in Lancaster and York counties that could be removed to improve water quality and fish populations.
The Tennessee Electric Cooperative Association is telling its customers that the Environmental Protection Agency’s 120-day public comment session is time for their voices to be heard. The group is asking its members to urge the EPA to make sure its recent emissions rules don’t cause more harm than good.
“The economic challenges faced by many cooperative members make it critical that EPA regulatory programs be cost-effective and provide environmental benefits that exceed the implementation and compliance costs,” said David Callis, the group’s executive vice president. “Estimates indicate that Tennessee will be among the hardest hit by the state requirements, calling for a 38% reduction in carbon dioxide emissions by 2030. These regulations will hurt Tennessee families, and we are just beginning to understand how severe the impacts will be.”
Gov. Terry McAuliffe Wednesday created an Energy Council to help develop recommendations for a state energy plan, which is to be submitted to the General Assembly in October. The governor said Virginia must come up with a strategic energy plan in order to maintain jobs in the energy sector and create new energy technologies. He called on the council to come up with ways to develop energy-efficiency programs and renewable energy sources.
Alexandria officials are questioning a Dominion plan to bury a 230-kV transmission line between the city and Arlington County, saying it appears most of the benefit of the line will go to businesses outside of the city.
Alexandria City Manager Rashad M. Young said the city was told the $160 million project was a way to “enable better regional electrical reliability and capacity.” Young said they later learned that “part of the need for this project is to feed data centers being constructed in Fairfax and Loudoun counties.” Dominion said the proposed transmission line would improve local reliability and was not in response to development in surrounding counties.
The company will appear at an Alexandria City Council meeting Wednesday to provide an overview of the proposal.
West Virginia University’s Center for Energy and Sustainable Development is teaming with environmental firm Downstream Strategies to help the state come up with ways to comply with the Environmental Protection Agency’s new emissions standards and reduce carbon dioxide emissions from coal-fired power plants by 20%.
The combined effort to develop the report is expected to be completed within the next year, according to Downstream Strategies’ Evan Hansen. “What’s important to realize is that a 20% reduction in carbon emissions doesn’t mean we would be mining 20% less coal or losing 20% of our coal jobs,” Hansen said. “There’s so much flexibility in this rule and it means that it can be achieved in many different ways. Coal production will continue.”
The Market Implementation Committee last week endorsed the removal of a requirement that interchange transactions last at least 45 minutes to comply with a mandate by the Federal Energy Regulatory Commission.
FERC ruled in April that PJM’s 45-minute rule did not comply with Order 764, which required 15-minute energy scheduling intervals with 20-minute notifications. (See FERC Rejects PJM Schedule Rules.)
The MIC waived the first read so the changes would be effective by the implementation date required in the FERC order. PJM removed the 45-minute restriction from the EES application and from the Regional Practices document effective May 19. The Markets and Reliability Committee endorsed the changes in May.
Order 764, issued in 2012, is intended to remove barriers to variable generation sources such as wind.
Exelon last week filed an application with the Federal Energy Regulatory Commission seeking approval of its acquisition of Pepco Holdings Inc. FERC approval is expected to come fairly swiftly, as PHI has no generation, and market power issues shouldn’t come into play.
The two companies announced the proposed acquisition late last month. If approved, it will bring together Exelon’s three electric and gas utilities – BGE, PECO and ComEd – with PHI’s three utilities – Delmarva Power, Pepco and Atlantic City Electric. The combined companies would become the largest electric and gas utility in the Mid-Atlantic.
Because no generation plants are involved, the companies are asking for approval within 90 days. The acquisition still requires approval from state regulatory agencies in Delaware, Maryland, New Jersey and Virginia, as well as from the D.C. Public Service Commission. Those approvals are expected to take longer to obtain. The companies have said they anticipate full approvals by the second or third quarter of 2015.
FERC has gained a valuable new tool in the fight against energy market manipulation as a result of an agreement giving the commission access to the Commodity Futures Trading Commission’s Large Trader Report. “Until recently, we didn’t have a lot of visibility into large trading data, [but] the CFTC has given us a lot more transparency in terms of positions,” Sean Collins, FERC’s deputy director of surveillance, told a conference in Texas last month.
Collins said the memorandum of understanding between the two organizations has given FERC investigators a clearer view of what is going on in the derivatives market, which often plays a crucial role in manipulative schemes that involve both physical and financial products. “The ability to see across those two markets and to be able to see what market participants are doing is essential, so we’re very thankful for that data,” he said.
Citing previous safety studies, the Nuclear Regulatory Commission rejected calls from lawmakers to speed up the transfer of spent fuel bundles from pools to dry cask storage.
The commission, relying on its staff’s recommendations, has said it believes it makes more sense to leave the spent rods in on-site cooling ponds than engage in hurry-up transfers to dry cask storage.
An NRC Northeast Regional administrator said both pools and dry casks were “adequate storage processes for spent fuel, and there is not a significant safety benefit to requiring transfer to dry cask storage.”
Some lawmakers, however, citing security concerns and dwindling space in cooling pools, are pushing for the transfers.
Several senators wrote to NRC Chair Allison Macfarlane earlier to complain about a lack of security around the pools and closed plants. “We are one natural disaster, mechanical failure or terrorist attack away from a disaster,” said Sen. Bernie Sanders (I-Vermont). “The sooner we get the spent [fuel] out of the pools and into dry casks, the better, and if the NRC will not change the rules, I will continue to work with my colleagues to change the rules through legislation.”
The EPA successfully fended off efforts by environmental groups to hasten implementation of rules combatting acid rain. The U.S. Court of Appeals for the D.C. Circuit last week accepted the EPA’s arguments that rules covering acid rain must take into account “large complexities” and shouldn’t be hurried. The EPA announced two years ago that it needed more time to determine new standards of certain pollutants, primarily those emitted by fossil-fuel fired power plants. Environmental groups, including the Center for Biological Diversity, sued and accused the EPA of delaying the implementation of new regulations.
“In light of the deference due EPA’s scientific judgment, it is clear its judgment must be sustained here,” U.S. Circuit Judge A. Raymond Randolph wrote for a three-judge panel.
A joint proposal from PJM and the Independent Market Monitor to reduce payments to frequently mitigated units (FMUs) rose from the ashes to best three generator-backed proposals last week.
The PJM-IMM proposal earned nearly 70% approval in a sector-weighted vote of the Markets and Reliability Committee, despite earning just 43% support from the Market Implementation Committee in early May. (See Members Reject PJM-IMM Plan on FMUs).
The proposal was approved after three packages favored by suppliers failed to earn enough support for approval.
Market Monitor Joe Bowring has said the adders are no longer needed because of PJM’s capacity market.
The PJM-IMM proposal (Package A) leaves the calculations for adder payments unchanged but limits them to units whose net revenues are not covering their avoidable cost rate (ACR). PJM said that had the proposal been in effect in 2013, it would have reduced the number of units receiving adders from 112 to only 28 — 23 of which are scheduled to retire.
Neil Fitch of NRG Energy said his company couldn’t support the PJM-IMM package because it “seems tantamount to eliminating FMUs.”
Package G, which was considered first based on the 65% support it received at the MIC, received only 40% support from the MRC. It would have capped adders at 12% of the gross Cost of New Entry (CONE).
Of the three generator-backed proposals, only Package H received more than 50% of sector-weighted support, though it didn’t come close to the two-thirds support needed for approval. It would change adders only for Tier 2 FMUs — units that are offer-capped between 70% and 80% of their run hours over the prior 12 months.
Members last week agreed to create a senior task force to fix the underfunding of Financial Transmission Rights (FTRs) following a debate over the role of Auction Revenue Rights.
PJM says over-allocation of Stage 1A ARRs have become the biggest cause of the problem, responsible for $420 million of underfunding for planning year 2013/14, 73% of the total. That was up sharply from 2012/13, when ARRs caused only 26% of underfunding, or $75 million. (See chart below.)
PJM agreed to modify the task force’s initiating documents to include an evaluation of the causes of underfunding after several stakeholders raised concerns that ARRs were being unfairly singled out. ARRs are allocated annually to firm transmission service customers and entitle them to receive a share of the revenues from the annual auction of FTRs.
Ed Tatum of Old Dominion Electric Cooperative objected to the original problem statement, which he said improperly included a solution that targeted ARRs.
ARRs are “a touchstone issue for the load-serving entities,” Tatum said. “We don’t believe the numbers [cited by PJM] reflect the actual impact of the problem … We think it’s a much lower number and we’d like to understand how PJM calculated it. It’s more than likely there are other, more significant causes of the underfunding.”
Andy Ott, executive vice president for markets, said PJM wanted to keep the issue scope narrow to avoid the “food fights” of the past.
PJM says more than 15% of Stage 1 historical generation (25,544 MW) has retired or submitted deactivation notices since the ARR allocation process was designed. “This is the biggest reason for underfunding,” said Harry Singh of Goldman Sachs. “You’re allocating things that don’t exist.”
Singh said a failure to address FTR over-allocation could jeopardize the Commodity Futures Trading Commission’s order exempting FTRs from the agency’s jurisdiction. The order said FTRs must “be limited by the physical capability of the … transmission system.”
The problem statement also identified other underfunding causes, including external loop flows, maintenance- and construction-related transmission outages and the creation of temporary interfaces to capture operating procedures — such as the dispatch of demand response — in locational marginal prices.
The RTO introduced FTRs in 1999, intending them to provide a financial hedge against the costs of day-ahead transmission congestion.
Singh said that load-serving entities “should also care about having good hedges.” Those who oppose solutions to the problem “are not doing a favor for the people they work for,” he said. Over-allocation to a handful of load-serving entities amounts to a subsidy by other LSEs, he said.
Ott said the task force, which will report to the MRC, should complete its work by Oct. 31, before the next annual FTR auction. “If we don’t deal with it by October, then we miss a whole year,” he said.
ROCKVILLE, Md. — “Clean” energy portfolio standards may be a way for states to provide financial support for ailing nuclear plants, Federal Energy Regulatory Commission officials said last week.
FERC Commissioner Phil Moeller, FERC Acting Chair Cheryl LaFleur, NRC Chair Allison MacFarlane (L to R)
The comments came during FERC’s public meeting with the Nuclear Regulatory Commission on grid reliability Wednesday. Officials of the North American Electric Reliability Corp. (NERC) also took part in the 90-minute session at NRC headquarters, which included discussions on NRC’s actions to address lessons learned in the 2011 Fukushima nuclear disaster and FERC’s regulation of hydropower dams near nuclear plants.
But coming on the heels of a capacity market auction in which five Exelon Corp. nuclear generating plants in Illinois failed to clear, the financial health of nuclear power was the central topic. (See related story How Exelon Won by Losing.)
FERC Commissioner Tony Clark noted that PJM and other organized wholesale markets have been able to coexist with state renewable portfolio standards (RPS) that ensure a place for wind and solar power in the generation mix.
“So an elegant solution might be pivoting to a clean-energy standard if the concern of a state is emissions and … if we’re moving into a 111(d) world where carbon is going to be regulated,” Clark said, referring to the greenhouse gas rule released by the EPA yesterday. “These would seem to be some of the most valuable units we have.”
Arnie Quinn, director of FERC’s Division of Economics and Technical Analysis, said such a structure might overcome the jurisdictional challenges that he said have “hamstrung” regulators in restructured states.
Quinn said state regulators have expressed a desire to obtain purchase-power contracts to keep their nuclear plants open. “They look [for someone] to sign that contract and they have difficulty finding who they still have jurisdiction over,” he said. In states with RPS, load-serving entities are obligated to purchase minimum percentages of renewable sources such as wind and solar.
Fuel Security
FERC is also considering ways to bolster nuclear generators’ capacity revenues, perhaps through a “fuel security” premium.
FERCs Arnie Quinn
Acting FERC Chair Cheryl LaFleur said although the wholesale markets are “fuel blind,” they also acquire resources that possess important capabilities, such as ramping, needed to keep the grid functioning. Fuel security could be such a capability to incorporate, she suggested.
In January, natural gas-fired plants had trouble obtaining fuel due to high prices and pipeline constraints. Coal-fired plants also experienced problems due to frozen coal and delayed rail shipments.
Nuclear plants need to add fuel about once every two years — about the same frequency with which FERC and NRC hold these joint meetings.
“Knowing that you’ve got a stock of fuel on site … that will be there for the duration of a weather event — it’s another thing you don’t have to” worry about, Quinn said.
Causes of Nukes’ Problems
Quinn cited data from the PJM Market Monitor showing that nuclear generators’ net energy and capacity revenues in the RTO have declined from more than $300,000/MW-year in 2010 and 2011 to $240,000 in 2013.
Quinn said the causes include excess supply, particularly from low-cost natural gas and wind, and capacity prices depressed by demand response and transmission upgrades.
Quinn said that fossil fuel plant retirements resulting from the EPA’s Mercury and Air Toxics Standards and transmission expansion that makes it easier for generators to reach load may help boost prices. “But the degree to which any of these future changes will result in a full recovery of revenue levels is just uncertain at this point,” he said.
Quinn also noted that nuclear plants benefited from energy market prices in January that hit $1,000/MWh during some hours.
“In some degree the system has been designed so that’s where a lot of cost recovery occurs … If your marginal cost was down at $15 to $20 per megawatt-hour there was a lot of money there to be earned to recover some fixed costs.”
The question FERC is considering, Quinn said, is whether current energy and capacity revenues are enough to preserve the nuclear fleet or whether it requires some other payment stream.
Duke Energy has reached an agreement with the EPA about the cleanup of its massive coal ash spill on the Dan River. The agreement formalizes the cleanup activities already underway after February’s spill of an estimated 39,000 tons of ash and includes ongoing monitoring and post-cleanup assessment. It also provides penalties of up to $8,000 per day if the company doesn’t follow the conditions. Duke agreed to pay the EPA’s costs for responding to the spill, estimated at $1 million so far. The agreement is filed under the federal Superfund hazardous sites law.
Duke Energy contractors and engineers survey the site of the coal ash spill on the Dan River in North Carolina.
Duke is also facing a stockholder suit over its potential liability for spills at its other coal ash depositories. The complaint by shareholders Edward Tansey and the Police Retirement System of St. Louis alleges management exposed the company to billions in liability over its coal ash storage methods.
The suit was filed in the Court of Chancery in Delaware, where Duke is incorporated. It claims that Duke officials were aware of the risk of coal ash contamination from its stock piles and settling ponds. It seeks to force the company to eliminate ash contamination, as well as unspecified damages and changes in how Duke handles the waste.
Meanwhile, a North Carolina House bill filed last week aims to force Duke to clean up its most dangerous coals ash ponds within the next five years. House Bill 1226, introduced by Democratic lawmakers, includes a long list of coal ash regulations, including a moratorium on accepting more coal ash starting this summer.
Most notable about the bill is a provision denying the company the ability to recover remediation costs from customers. In addition to stopping new coal ash deliveries, the bill calls for all coal ash storage ponds to be closed by 2029 and the most dangerous coal ash ponds cleaned up by 2019.
American Electric Power Company is reportedly pondering the sale of its Midwestern power plants, becoming the second large generation owner, after Duke, to exit the Midwest regional generating business.
CEO Nick Atkins told Bloomberg that because of the paucity of long-term power purchasers, which bring certainty to merchant plants, the company could decide to concentrate almost exclusively on its regulated businesses, with their guaranteed rates of return.
Duke is seeking to sell 13 plants that produce 6,600 MW. AEP owns more than 10,000 MW of generation, valued at about $3 billion. The company said a final decision on whether to sell should come by the end of the year.
Exelon’s aging Oyster Creek nuclear power station last Wednesday reported a leak of chlorine used to control algae near the plant’s water intakes, but the plant remained at full power, authorities said. The “unusual event” was declared at 10:30 a.m. and ended an hour later, according to Nuclear Regulatory Commission spokesman Neil Sheehan. No one was hurt. Oyster Creek is scheduled to be retired in 2019.
Susquehanna 1 Refueling Done
But Turbine Work Needed
PPL’s Susquehanna Unit 1 will remain offline indefinitely while the company investigates the cause of turbine issues the unit experienced a year ago. The refueling and scheduled maintenance outage work on the 1,260-MW Unit 1 was done last week, but the plant on the Susquehanna River will stay cold while engineers inspect the low-pressure steam turbine. The company did not say when it would return to service.
Unit 1’s turbines have been inspected five times since 2011. Unit 2’s turbines have been inspected at least six times, most recently in March. Unit 2 remains operating at full power, according to the NRC.
PJM told the Federal Energy Regulatory Commission last week it should allow a Duke Energy peaking plant to recover $9.8 million it spent on expensive natural gas it was unable to burn in January.
Responding to a complaint filed by Duke May 2 (EL14-45), PJM disagreed with Duke’s legal analysis and some aspects of its claim. But it said not paying Duke under the circumstances would be an “[in]equitable result” for generation owners.
The Market Monitor and others argued against Duke’s claim, saying capacity resources such as Duke need to be responsible for their fuel-cost risk.
What’s at Stake
If FERC rules in Duke’s favor, PJM’s tab could total tens of millions. In a filing supporting Duke’s claim, NextEra Energy Resources said it will make a similar claim to recoup $1.3 million in gas costs. Mike Bryson, executive director of system operations, told RTO Insider last week that about 10 companies have informed PJM that they also suffered “stranded gas” losses.
On Thursday, the Markets and Reliability Committee approved a problem statement to improve PJM’s procedure for committing gas-fired units. The initiative was broadened at stakeholders’ suggestions to cover several additional issues, including the definition of an outage and handling of dual-fuel units. “We’d like to get [solutions] before the winter so we don’t have a replay of the confusion” of January, said Mike Kormos, executive vice president for operations.
Duke’s Claim
Duke’s claim resulted from the late January cold snap. On Jan. 27, PJM issued a Maximum Generation Alert for the following day, signaling that all generation capacity resources should be ready to operate. (See related story, Recordings Capture Tense Operations During January Cold.)
Duke Lee Energy Facility (Source: Bill Spindler, SouthPoleStation.com)
As a result, Duke purchased $12.5 million worth of gas, enough to run five of the eight 80-MW units at its Lee County, Ill., facility for both Jan. 27 and 28. (Due to the mismatch of the gas and electric days and pipeline restrictions, Duke needed to purchase enough gas for two 24-hour periods in order to cover all hours for Jan. 28.)
Duke said it was able to recoup $2.6 million by self-scheduling several of the Lee units on Jan. 27 and 28, selling unused gas and receiving “very limited make-whole payments and credits” from PJM, leaving it with a loss of about $9.8 million.
Duke asked PJM to indemnify it under section 10.3 of the PJM Tariff, which requires that a generation owner be held “harmless” for “obligations … to third parties, arising out of … a Generation Owner’s (acting in good faith to implement or comply with the directives of the Transmission Provider) performance of its obligations.”
As an alternative, Duke seeks “a one-time, Duke-specific waiver” of Operating Agreement and Tariff provisions that bar make-whole payments.
PJM: No Order
In its filing last week, PJM insisted that its conversations with Duke did not constitute a directive to buy gas.
“It is a common occurrence that PJM dispatchers indicate that units need to be available to run only to later find that due to changes in load conditions, PJM does not need to commit the particular unit,” PJM said. “Although clearly done under more stressful conditions here, dispatchers are called on a routine basis and asked to prognosticate on whether units might be picked up and run in real time. Dispatchers answer those questions based on the best information they have available but are not providing guaranties through their answer.”
PJM also disagreed with Duke’s request for indemnification under the Tariff.
“Any extension of Section 10.3 to cover the type of loss Duke incurred under the circumstances at issue would read the indemnification provision into a blanket insurance policy for losses of whatever sort, caused by accident, act of God or plain misfortune that a Market Seller may incur in responding to PJM dispatch,” PJM said.
Commission approval of Duke’s request, PJM said, “would open the floodgates for a host of meritless claims that would present an existential threat to PJM and every independent system operator and regional transmission organization.”
PJM said capacity resources such as Lee must be offered into PJM’s markets on a daily basis and “do not have an automatic right to recover all of its costs should the units not actually be dispatched.”
Nevertheless, it said Duke should be compensated under a waiver because of the “extraordinary” circumstances of January. “Gas balancing losses that are usually no more than a routine `cost of doing business’ were in some cases transformed, in large part due to the conditions of the gas market and large price fluctuations, into multi-million dollar losses,” PJM said.
Monitor: Don’t Pay
In its own filing last week, the Market Monitor called on FERC to reject Duke’s request, saying it would be “a dramatic change in market rules and an associated, inappropriate shift in the costs and risks of the market to customers.”
The Monitor said Duke chose to rely solely on interruptible gas pipeline service and did not invest in back up fuel capability. “It is inappropriate for Duke to ask PJM customers to hold it harmless from such decisions, from which Duke has benefitted. It is also unfair to Duke’s competitors, who may have made different choices about fuel supply.”
The Monitor also said more than half of Duke’s claimed losses resulted from its delay in purchasing gas, which rose from $37/mmBtu to $63/mmBtu in the hours before Duke decided to purchase.
Retailers and the PJM Industrial Customer Coalition were also unsympathetic. The “waiver would harm the market, principles of market certainty and market participants … who may be forced to pay even more for Balancing Operating Reserve costs,” said the Retail Energy Supply Association.
Several generators, the PJM Power Providers Group and the Electric Power Supply Association filed comments siding with Duke.
“Denying Duke’s complaint despite Duke’s good faith efforts to comply with the PJM directive would be unjust and unreasonable,” FirstEnergy said. “System dispatchers need to have confidence that resources will perform when instructed to do so. And market participants must have confidence that, when directed by system operators to act for the sake of reliability, they will be made whole for the costs to carry out dispatcher’s instructions.”
NextEra Energy Resources also supported Duke, saying it also suffered losses in late January. NextEra said PJM “committed” a 290-MW generator in Sayreville, N.J., that NextEra co-owns with GDF Suez before the Jan. 27 operating day. PJM cancelled its dispatch, leaving the plant with a $1.3 million loss for unburned gas.
NextEra’s filing included a transcript of its exchange with PJM, in which one PJM dispatcher assured the company it would be reimbursed for its gas purchases: “I understand that you guys have already purchased the gas, ah, that’s not an issue, as far as if you’re worried about being reimbursed for that … PJM will obviously take care of that.”
A subsidiary of NRG Energy announced late last week that it will buy the largest wind farm in North America for $870 million. The deal is seen as another move by NRG to bulk up its portfolio of renewable energy, especially important now that the Environmental Protection Agency has issued its carbon emission reduction rules.
The Wall Street Journal reported last week that Dynegy is among those bidding for Duke Energy’s 11 fossil fuel-fired plants in the Midwest, going up against Blackstone Group and Riverstone Holdings. Citing unnamed sources, the Journal said that Dynegy, less than two years from emerging from bankruptcy, is looking increase its customer base. The plants, in Ohio, Illinois and Pennsylvania, are expected to sell for about $2.5 billion.
