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.
Questions multiplied faster than answers last week following an appellate court ruling that threw out the Federal Energy Regulatory Commission’s jurisdiction over demand response compensation.
Market leader EnerNOC issued a statement May 27 saying that the energy payments that are the subject of Order 745 were responsible for only 2% of the company’s $1 billion of revenue over the last three years.
“EnerNOC’s preliminary estimate of the impact of Friday’s decision suggests that EnerNOC and its customers could be required to refund in a future period as little as $0 and as much as $20 million if Friday’s decision on Order 745 survives any continued appeals process. Order 745 does not pertain to capacity payments which the Company is contractually due or has previously earned.”
FirstEnergy sees it differently. It reacted to the court ruling by filing a complaint (EL14-55) seeking to bar DR from the capacity market.
FirstEnergy’s complaint asked FERC to order the removal of “all portions of the PJM Tariff allowing or requiring PJM to include demand response as suppliers to PJM’s capacity markets.”
The company also asked FERC to bar PJM from releasing the results of the May capacity auction, saying it “must be considered void and legally invalid because the inclusion of demand response in the auction parameters was unlawful.”
EnerNOC said Tuesday that it cleared about 4,000 MW of DR worth more than $185 million. The company’s shares jumped more than 10% on the news but gave back most of that by the end of the week.
EnerNOC said it “would expect state regulators to take a much more active role in facilitating demand response activity. If the decision is broadened to include capacity and ancillary services markets, the Company would expect state programs to expand significantly to preserve the nearly $12 billion of consumer savings that demand response delivered last year in the PJM market.”
Exelon CEO Christopher Crane told an investment conference last week that the ruling could mean DR looks “less like a supply and more like a demand element.”
States taking over DR regulations could result in disparate rules, UBS Securities said. “We see the potential for more generous compensation in jurisdictions encouraging participation, while those that have been opposed, implementing tighter rules. Additionally, under state regulation, it would appear that utilities might ultimately be the entities controlling the bidding-in of DR products.”
At last week’s Markets and Reliability Committee meeting, PJM officials said they were awaiting guidance from FERC.
“For now, it’s business as usual for PJM, for PJM markets,” Assistant General Counsel Jackie Hugee said. “As of today, we still have a Tariff and an Operating Agreement in full force.”
The court’s order won’t take effect until at least mid-July to allow time for motions for rehearing, she said.
Hugee also said the ruling is likely to stand because there are no conflicting rulings in other jurisdictions that might prompt the circuit or Supreme Court to reconsider it. “It’s rare that a circuit court will grant rehearing of one of its orders,” she said.
“Our primary hope is [that] it will not be disruptive this summer,” when PJM typically calls on DR to reduce peak load, Executive Vice President for Operations Mike Kormos said.
Marji Philips of Direct Energy asked whether states might delegate management of DR to PJM, similar to the arrangement that governs the Generation Attribute Tracking System (GATS), which states use in awarding renewable energy credits (RECs).
Kormos said PJM will “reach out to the states” to determine their response to the ruling.
To support its claim for recovery of $9.8 million in “stranded” gas, Duke Energy filed audio recordings and transcripts of its conversations with PJM dispatchers on Jan. 27 and 28. Duke said it included the audio to emphasize “the urgency of the communication and the emergency circumstances it reflected.”
Below is a summary of those conversations, which offer a behind-the-scenes look at PJM operations under extreme stress.
Maximum Generation Alert
PJM Control Room (source: PJM Interconnection, LLC)
At 8:45 a.m. on Jan. 27, PJM issued a Maximum Generation Alert for the following day, signaling that all generation capacity resources should be ready to operate. The RTO estimated peak load of 141,000 MW, leaving it with only 1,000 MW of reserves, a fraction of its 9,450 MW reserve objective. It also issued a voltage reduction alert for the day.
A few minutes after the alerts, Greg Cecil, managing director of generation dispatch and logistics for Duke’s Midwest Commercial Generation unit, called PJM to inform dispatchers that gas might be a “limiting factor” in its ability to run its Lee County, Ill., generators the following day.
Cecil told PJM Master Dispatcher Nathan Marr he might be able to buy gas for the following day. “But if I do that, I’ve got to be able come on, and last time we did this, you guys would not let us come on,” Cecil said. At the time, gas on the pipeline supplying the Lee plant was selling for $37/mmBtu.
99.9% Certain
After first telling Cecil he “cannot anticipate” whether the plant will be needed, Marr continued, “More than likely, your units will be running.” Barring transmission constraints, Marr said, he was “99.9% [certain] you will run.”
“If you can secure gas, we would advise you to secure gas for your units,” Marr continued. “We want all units available for tomorrow.”
Marr reiterated PJM’s need for “all units” in two subsequent calls a few minutes later, at one point telling another Duke employee “if [Cecil’s] not securing gas based on an economic decision — this is not an economic decision. This is a reliability issue, so all units must be available.”
Shortly before the noon offer deadline for the day‐ahead energy market, Duke purchased $12.46 million worth of gas, enough to run five of its eight plants on 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.) The five units cleared in the day‐ahead market for hours ending 0800 through 1200 and hours ending 1900 through 2100.
$12 Million of Gas
Shortly after 7 a.m. on Jan. 28, Duke’s Cecil called Marr to ask whether his plant was likely to be dispatched in the real-time market. “What’s going to be the state of Lee today? Cause we’re sitting on $12 million worth of gas … And, I’ve got to do something with it,” he said.
“Right now, I’m not calling any units on,” Marr responded. “The loads are not coming in where we anticipated it.”
Marr then told Cecil there was a chance the plant would be dispatched in the evening. Cecil replied that if he sold gas it would delay the ability of the plant to begin generation.
“That [risk is] part of having a gas unit, I guess,” Marr said. “I mean, I don’t know what to tell you … You’re going to have to do whatever you have to do.”
The morning peak would hit only 133,137 MW — 4,500 MW below forecast. The evening peak, 137,336 MW, was PJM’s fourth highest winter peak on record. But it was almost 3,100 MW below forecast, and interchange provided an unusually large 6,500 MW. Additionally, generating resources performed better than expected with an 11% forced outage rate, half what it had been earlier in the month.
Stakeholders approved a problem statement last week that could make it easier for banks to purchase capacity providers’ revenue streams.
Under current rules, these “auction-specific” transactions cannot be submitted to PJM until after the third incremental auction for a delivery year.
Barry Trayers of Citigroup Energy, who presented the initiative to the Markets and Reliability Committee, would like the rules changed to allow the transactions to be entered into PJM’s eRPM system after the auction that initiated them.
Trayers said the current rules were instituted to ensure that Reliability Pricing Mechanism transactions involved physical capacity. Trayers said the delay is unnecessary because PJM filings with the Federal Energy Regulatory Commission have clarified that all capacity transactions are physical.
He said the performance risk remains with the original capacity seller, but if they should default, the buyer of the auction-specific transaction would be on the hook. Other stakeholders would only be at risk should both entities default.
Trayers initially proposed that the MRC approve the rule change immediately, but stakeholders were hesitant to do so.
Dave Pratzon of GT Power Group said he would vote against the solution because the agenda listed a vote for the problem statement only. “I am unsure of what the implications are,” he said.
The problem statement was approved unanimously. The issue will be considered by the Market Implementation Committee.
PJM said yesterday that the flexibility included in the Environmental Protection Agency’s proposed carbon emission rule is “an encouraging sign.”
PJM and other grid operators have called for a “reliability safety valve,” similar to that in the EPA’s Mercury and Air Toxics rule, which would allow the EPA to relax or delay implementing the standards in a region whose reliability would otherwise be threatened. (See related story, Carbon Rule Falls Unevenly on PJM States.) Grid operators also asked for regional compliance measurement so that states can take advantage of the efficiencies of integrated generation dispatch across multiple states.
Several PJM member companies weighed in with their own reactions yesterday, while their stock prices barely budged:
AEP
“It appears that for some states where we operate, the reduction requirements could be much more than 30% by 2030. Climate change is a global issue, and some states should not bear a disproportionate share of the cost of U.S. action to cut emissions.
“AEP is retiring more than one-fourth of our existing coal-fueled power plant fleet in the next few years. The plants that remain are the most efficient in our fleet and are equipped with more than $10 billion worth of emission controls that were installed to meet other EPA requirements. The investments that our customers made in these plants should not be prematurely lost when ultimately, it will have no impact on growing global greenhouse gas concentrations.”
AEP showed a modest gain, closing at $53.48, up 13 cents, or 0.24%
Calpine
“Calpine supports the EPA’s proposal because we believe it will ensure continued progress toward cleaner energy in a way that supports ongoing grid reliability while allowing market forces to work to deliver the lowest-cost solution for reducing GHG emissions,” said Thad Hill, Chief Executive Officer of Calpine.
Calpine, which has invested heavily in natural gas-fired generation, showed a modest gain, climbing up 15 cents to close at $23.47, up 0.64%.
Exelon
“We have just received the draft rule and are reviewing it and cannot provide any detailed comments at this point,” Exelon spokesman Paul Elsberg said. “However, we are pleased that the draft rule recognizes the critical importance of supporting the continued operation of the nation’s nuclear fleet. We look forward to working with EPA and key stakeholders during the coming months as the rule is finalized.”
Exelon closed at $36.60, down 23 cents, or 0.62%.
FirstEnergy
“Through investments in plant efficiency and multiple plant retirements, FirstEnergy expects a 25% reduction below 2005 levels in CO2 emissions by 2015,” company spokeswoman Stephanie Walton said. “This puts the company on target to meet the Obama Administration’s goal of a 30% percent reduction in greenhouse gas emissions by 2030, if credit is given for plants retired since 2005.
“Following our initial review, FirstEnergy believes it is in a strong position to meet the requirements outlined in the proposed rule, given our expected CO2 reductions in the coming years,” she said. “We are still reviewing how plant retirements will be counted towards the reduction target. As proposed, the rule uses an appropriate baseline year, provides states with reasonable flexibility, and gives an adequate compliance timeline.”
FirstEnergy closed down 27 cents, or 0.80%, closing at $33.55.
NRG Energy
“NRG views achieving significant GHG emission reductions — domestically and globally — as essential for creating sustainable businesses and a sustainable economy,” NRG said in a statement.
“Policies that focus on moderate, near-term emissions reductions, coupled with more aggressive out-year targets, will allow NRG and the rest of the power sector to continue to deploy a wide variety of clean energy solutions.
“Based on our initial reading of the EPA’s proposed GHG rule for existing power plants, we have concerns that EPA’s dramatically varying state emission targets may derail these objectives by adversely impacting electricity reliability and consumers in certain states and introducing excessive uncertainty and legal risk around the important objective of reducing GHG emissions.”
NRG Energy closed at $35.63, down a penny, or 0.03%.
PJM won stakeholder approval of its short-term plan for capturing reserve costs in energy prices after agreeing to a sunset provision that won over load representatives.
The Markets and Reliability Committee initially rejected PJM’s plan by a 49-64 vote, with only a single vote from End Use Customers and none from Electric Distributors.
The committee then approved by an 87-4 margin an alternative proposed by Direct Energy’s David “Scarp” Scarpignato that would sunset the plan on Sept. 30, with PJM filing a proposed long-term solution with the Federal Energy Regulatory Commission Oct. 1. Later in the meeting, the MRC also approved a problem statement on the long-term solution.
Critics repeated those concerns at the MRC meeting Thursday. Scarp said that by putting the cost of reserves into LMPs, which are borne by load only, the proposal violated cost-causation principles. “Generators failing to start, at least today, they pick up some of that” cost, he said.
Ed Tatum of Old Dominion Electric Cooperative agreed. “We feel that we’re rushing into a solution that will have dire unintended consequences,” he said. “All of the sudden load is going to start picking up [the cost of] operational problems.”
Tatum also questioned how such a significant change could be accomplished by only a manual change, rather than a Tariff change that would require FERC approval.
Harry Singh of Goldman Sachs acknowledged that the increase in LMPs is likely to exceed the uplift costs because marginal costs are higher than average costs. But he said the LMP costs can be hedged, unlike uplift.
After the first vote failed, members quickly coalesced around Scarp’s proposal, for which he had been building support for weeks.
The sunset proposal “moves the ball forward,” Executive Vice President of Markets Andy Ott said. “It gives us a chance to evaluate the impact [of the change] during the summer. It’s a workable way forward while still respecting the concerns raised.”
Plan Described
PJM’s short-term plan would increase day-ahead and real-time reserve requirements when Hot- or Cold-Weather Alerts or Max Emergency Generation alerts are issued for the RTO or for either the Mid-Atlantic-Dominion or Mid-Atlantic regions.
The adder for day-ahead reserves would be set at 3% of forecasted load, boosting reserves from 6.27% to 9.27%. The real-time reserve adder would be equal to the default Mid-Atlantic-Dominion synchronized reserve requirement of 1,300 MW.
The increased reserves would be reflected in market clearing engines, ensuring that the costs go into locational marginal prices and not uplift.
Long-Term Solution Sought
The MRC also approved a problem statement and issue charge giving the Energy and Reserve Pricing and Interchange Volatility (ERPIV) stakeholder group authority to develop long-term solutions to the problem, which would likely involve Tariff changes and revisions to PJM software. The expansion of the ERPIV charter passed by acclamation.
Stakeholders last week approved new rules designed to ease the way for public policy transmission projects, but Maryland regulators said the “multi-driver” approach may be irrelevant because of parallel cost allocation rules proposed by PJM Transmission Owners.
The Markets and Reliability Committee Thursday approved Operating Agreement and Tariff revisions that envision two types of multi-driver projects:
The “incremental” method would be used when the multi-driver project was developed as a result of a single driver, such as reliability or market efficiency, but is modified to satisfy one or more other goals and becomes a more cost-effective solution to all of the drivers. Under the TOs’ proposal, the original driver would have its cost allocation reduced by “an amount equal to the ratio of the estimated incremental cost of the new driver(s) to the estimated new total cost of the project multiplied by the estimated cost of the original driver.”
The “proportional” method would be used when the multi-driver project is developed in parallel with individual solutions to different drivers and then combined. The TOs would allocate costs based on the relative costs of the individual projects that would have been required to address each driver alone.
Stakeholders won’t get a vote on the TOs’ proposal, although the TOs are accepting comments on the plan through June 6. The opportunity for opponents to challenge the proposal will come after the TOs make a Section 205 filing seeking Federal Energy Regulatory Commission approval.
“We are one of those who are very concerned with the TOs’ cost allocation” proposal, Walter Hall of the Maryland Public Service Commission told the MRC. Hall said the OA and Tariff changes approved Thursday “may become much ado about nothing” because the TOs’ cost allocation may make public policy projects too expensive to pursue.
John Farber of the Delaware Public Service Commission said that PJM, which will administer the cost allocation process, should use a case-by-case approach for evaluating the relative benefits rather than the “formulaic, rigid approach” envisioned under the TOs’ plan.
Steve Herling, vice president of planning, said Farber’s proposal was unworkable. Cost allocation “has to be formulaic,” Herling said. If the RTO did evaluations project by project, “we’d spend all our time doing cost allocation,” he said.
The states say the rules being drafted by the TOs differ from those outlined by PJM last year.
In a presentation to the Regional Planning Process Task Force (RRPTF) in August, the incremental approach envisioned public policy projects being allocated only the costs added to the proposal to accommodate the public policy needs. For example, if a $250 million project originally designed for reliability and market efficiency grew to $600 million as a result of the public policy needs, public policy would be apportioned only the $350 million additional cost.
Under the current TO proposal, however, the original drivers would receive a credit for some of their costs, with public policy paying more than just its incremental increase.
For example, if a $300 million reliability project expanded to $400 million to accommodate public policy, the public policy would be allocated $175 million — the incremental $100 million plus an additional $75 million based on the ratio of the incremental cost to the total cost. The costs allocated to the reliability portion would be reduced from $300 million to $225 million. (See chart)
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.
