The short history of merchant generation in the U.S. is strewn with the fragments of once high-flying Wall Street darlings that crashed and burned. Remember Sithe? Boston Generating? Orion?
And it’s not just small, under-capitalized operations or industry newcomers that have found the merchant generator model perilous.
Miami Fort Station (Source: Duke Energy)
Duke Energy Corp., the largest U.S. utility owner, announced last week that it no longer wants to be in the merchant generation business in the Midwest, and is selling its interest in 13 power plants in Ohio, Illinois and Pennsylvania.
Duke’s decision to sell 6,600 MW of generation — the bulk of its merchant fleet — came just days after the Ohio PUC refused the company’s request to bill regulated customers $729 million to make up for a shortfall between generation power costs and plunging wholesale power prices. The company said that it expects to take a charge of $1 billion to $2 billion from the sale, which they expect to close in 12 to 18 months.
Its decision to take a loss to get out of that part of the business came not just because of the shortfall.
Too Volatile
“Our merchant power plants have delivered volatile returns in the challenging competitive market in the Midwest,” said Duke Energy President and CEO Lynn Good. “This earnings profile is not a strategic fit for Duke Energy.”
Companies like to give investors what they want, and investors value certainty. A market that swings on fuel prices, volatile markets and weather is not certain.
It’s not just Duke that finds itself in the vise of high generation costs and low wholesale prices on the power market.
St. Louis-based Ameren Corp. exited the merchant generation business entirely late last year when it sold its five coal-fired plants in Illinois to Dynegy. It cited, in part, a desire to concentrate on its regulated – read more predictable – electric, natural gas and transmission operations.
FirstEnergy last month cut its dividend by more than one-third and announced a renewed focus on regulated operations after a year in which the company’s stock fell 20% on weak earnings from its unregulated unit. (See Reboot for FirstEnergy.)
Exelon, which cut its dividend by more than 40% a year ago, announced last month that it might mothball some of its nuclear stations in the face of what it says is unfairly subsidized renewable power and stiff competition from gas-fired generation. “Despite our best ever year in generation some of our nuclear units are unprofitable at this point in the current environment due to the low prices and bad energy policy,” Exelon CEO Chris Crane said. (See Exelon May Close Nukes.)
Julien Dumoulin-Smith
Julien Dumoulin-Smith, an analyst for UBS Investment Research, told the PJM General Session Feb. 12 that locational marginal prices at Exelon’s Quad Cities nuclear plant on the wind-rich Illinois-Iowa border were negative in more than 1% of the hours in 2013, with an average negative prices of -$15.35/MWh. For all hours, average LMPs were less than $26/MWh.
De-Integration
Dumoulin-Smith said the Duke announcement is further evidence of what he called the “gradual de-integration” of the industry, and predicted other publicly traded utilities will also withdraw from the merchant generation business to concentrate on their regulated businesses.
Paul Fremont, analyst with Jeffries & Company, wouldn’t draw industry-wide conclusions in the wake of Duke’s announcement, but said some companies have already indicated a strategy that doesn’t concentrate on merchant generation. “Dominion not going to increase exposure” in merchant generation, he said, “and I think PPL has indicated it may exit.”
Dominion is among the utilities that have scaled back their non-regulated businesses. It announced at the end of January that it was selling its retail electric business, perhaps by the end of this quarter. “The margins in the electric side of business have been shrinking,” Dominion CEO Tom Farrell said during an earnings conference call. “And you see increased volatility happening.”
Shrinkage Among IPPs?
The stresses faced by merchant arms of integrated utilities also face pure-play independent power producers. Before long, suggested Dumoulin-Smith, “there’s going to be three or four IPPs left…Maybe two?”
He said it’s conceivable that a merchant nuclear portfolio could drop below investment grade, suggesting a roll-up by an IPP would obtain a single B credit rating. But with debt so cheap, he said, “I’m not sure it matters a heck of a lot.”
Impact on Midwest Capacity
Duke’s exit plan, and Exelon’s warnings, comes on top of a wave of coal plant closures resulting from environmental regulations and low natural gas prices.
MISO late last year predicted a shortfall of 5 to 7 gigawatts of capacity in 2016-17 due to loss of coal-fired generation. A survey released this month, however, suggested the shortfall might be only 2 GW or less.
RGGI Funds Set for Several Vehicle Charging Stations
The state Department of Natural Resources and Environmental Controls and the University of Delaware plan to place electric vehicle charging stations at five or six locations in the state, with two chargers at each site. The program, with an $80,000 budget from proceeds of the Regional Greenhouse Gas Initiative, aims to locate the stations so that lower-cost EVs, which have limited driving ranges, can make in-state trips conveniently. Charging is expected to be free at first.
Plans for a 279 MW combined heat and power plant at a new data center in Newark have stirred criticism by people who say the facility could reduce its carbon footprint by using renewable energy. The project, at the site of a former Chrysler factory, would be fired by natural gas. Project supporters have cited a generic document from the Environmental Protection Agency describing the energy efficiency and environmental benefits of CHP.
The union representing operators at five Exelon nuclear plants in northern Illinois filed a class-action suit against the company, alleging violations of state and federal wage laws. Exelon does not pay the operators for time they have to spend before and after their shifts, filling out documentation and consulting with one another on operational issues, according to the suit by Local 15 of the International Brotherhood of Electrical Workers. Operators at the Clinton nuclear plant, in southern Illinois, who are represented by a different IBEW local, are paid for the extra time.
City Could Hike Sales Tax Because of Prairie State
The Batavia City Council is considering raising sales taxes to reduce the electricity rate increase it expects to impose this spring because of its high-cost power purchases from the new Prairie State Energy Campus. A member of the Northern Illinois Municipal Power Agency, Batavia is obliged to buy some of the coal plant’s output. Raising sales taxes one-half cent would limit the rate increase to 10% instead of 16%.
Pittsburgh-based EverPower Wind Holdings will buy the 240 MW Big Sky merchant wind farm through a two-step arrangement with turbine manufacturer Suzlon, a first priority lien holder in Big Sky. Edison Mission Energy is selling the facility as part of its bankruptcy proceedings.
In a Feb. 7 filing with the Federal Energy Regulatory Commission, the companies said Suzlon would buy Big Sky for a nominal sum in exchange for forgiving Big Sky’s debt. EverPower would then acquire the project, allowing Suzlon to recoup the debt that was forgiven. Edison Mission, Suzlon and EverPower asked for FERC approval by March 5 to enable the transaction, which they said would help Edison exit bankruptcy in the first part of this year.
Suzlon expects to recover about $90 million of the $228 million Edison Mission owes. The turbine manufacturer itself is in default on $209 million of bonds.
The Illinois Commerce Commission approved a certificate for FutureGen 2.0 to build and operate a carbon dioxide pipeline in connection with the carbon capture and sequestration project planned for the state. Construction cannot start until all permits are in hand, according to the ICC order, but FutureGen does not have to wait for all permits before exercising eminent domain for the pipeline route.
Six names are on the list to fill two seats on the Utility Regulatory Commission being vacated soon. After interviewing 21 candidates, the IURC Nominating Committee forwarded six names to Gov. Mike Pence for consideration: Jim Ray, Robert Hartley, Michael Musa, Carol Stephan and Angela Weber. Two of them will succeed Kari Bennett, whose term expires at the end of March, and Larry Landis, who is retiring.
In other IURC news, the state Supreme Court issued a public reprimand to the commission’s former general counsel, Scott Storms, for negotiating a job with Duke Energy in 2010 while the commission was considering whether to have ratepayers bear cost overruns of the Edwardsport coal gasification plant. A reprimand, which was agreed to by Storms, is the lightest punishment for legal misconduct. In connection with the 2010 events, the Indiana Attorney General’s Office is appealing a ruling last year that dismissed misconduct charges against former commission Chairman David Lott Hardy.
NiSource Grid Plan OK’d; CEO skirts Dominion rumor
Northern Indiana Public Service won regulatory approval for its seven-year, $1.1 billion system upgrade plan, calling it a “vital, significant milestone” for the NiSource subsidiary. Rate increases through a new bill surcharge would average 0.9% a year, starting in 2017 with a charge that would increase through 2020. The surcharge would pay for 80% of the project costs; 20% would be deferred to Nipsco’s next rate case. The utility’s plan includes replacing 50-year-old power lines and 40-year-old wood poles.
Also last week, NiSource said during an earnings call with analysts that it expects to spend about $2.5 billion on electric infrastructure projects, and sees the potential for $6.4 billion in that spending. Questioned during the call, CEO Richard Skaggs did not directly rebut rumors that Dominion Resources may be looking to buy a midwestern utility such as NiSource.
TVA to Replace 2 Paradise Units with Combined-Cycle
The Tennessee Valley Authority will replace Units 1 and 2 at the Paradise Fossil Plant with a $1 billion combined-cycle gas plant by the summer of 2017. TVA’s board, which seeks to fuel 20% of its generation by gas, voted in November to shut the units down.
The Public Service Commission approved East Kentucky Power Cooperative’s plan to bring emission controls at Unit 1 of its J.S. Cooper Generating Station into compliance with federal standards and to recover the cost through the co-op’s environmental surcharge. The $15 million project will add ductwork to redirect emissions from the 116-MW Unit 1 to control equipment already in place for emissions from the 225-MW Unit 2.
Panel OKs Bill to Set CO2 Rules That Preserve Coal
Rep. Jim Gooch
The House Committee on Resources and the Environment approved a bill that would establish a coal-friendly plan for use when Kentucky has to comply with a federal carbon dioxide control program for existing power plants. Sponsored by committee Chairman Rep. Jim Gooch, who co-owns a coal mining manufacturing business, the measure instructs the state Energy and Environment Cabinet to create a plan that considers the economic impact of CO2 emissions, sets flexible standards and does not require fuel switching or carbon capture and storage.
The cabinet called the bill premature and said it could limit the state’s flexibility once the Environmental Protection Agency issues the guidelines for existing plants. Cabinet Secretary Len Peters has sent EPA a suggestion for structure of a program with features Kentucky could work with.
The state Senate Executive Nominations Committee approved Gov. Martin O’Malley’s nomination of Anne Hoskins to the Public Service Commission, over some Montgomery County citizen protests. Hoskins, a former senior vice president of Public Service Enterprise Group, would be biased toward utilities, some said. She has been serving in a provisional capacity since O’Malley appointed her in August. The full Senate now must vote on the nomination.
Montgomery Sen. Rich Madaleno (D-18) requested that the nomination be discussed separately on the Senate floor. His move would allow opponents to highlight the PSC’s approval of trackers, which allow utilities to receive earlier reimbursement of investments. Hoskins favors trackers.
DTE Chief Sees the State Keeping Lid on Competition
DTE Energy sees little chance for expanding retail competition in Michigan, especially as this winter’s volatile markets have stressed other retail markets. “Those markets are in trouble and I think an increasing number of observers believe that,” Chairman and chief executive Gerry Anderson said in an earnings call with analysts. “I don’t think Michigan has an appetite for stepping into that.” Lawmakers are considering whether to lift the 10% retail-shopping cap in current law.
$210 Million Fund Would Enable Resiliency Measures
As part of a plan to use $1.46 billion in federal money in a second wave of Hurricane Sandy recovery work, the state has proposed a $210 million fund for an Energy Resilience Bank, which would focus on distributed energy projects to provide power “in the event the larger electrical grid fails.” The bank’s loans, loan guarantees and other measures would come from leveraging federal money with state and private money. Separately, a $225 million allocation would go to help local governments meet matching-fund obligations for projects that could include power generation and distribution facilities.
The Board of Public Utilities ordered development of a vegetation management plan to reduce distribution-level power outages caused by trees. More than 100,000 trees fell on power lines in Hurricane Sandy, causing widespread outages. At its March meeting, the BPU is to consider a proposal to establish a tracking system for tree-related outages that would provide information on trees that are likely to fall on power lines and whether they are in utilities’ rights of way.
Jersey Central Power & Light will spend more than $250 million this year, $50 million more than last year, on projects to strengthen its grid. The FirstEnergy company’s announcement comes as JCP&L is dealing with strong pushback from consumers and regulatory commission staff, who want the utility’s rates cut. About 90% of the company’s customers lost power for several days during Hurricane Sandy. About 60% of the spending this year is for transmission investments, including a new high-voltage line between Manalapan and Hightstown. The company also plans a smart grid initiative in Morris County.
An investigation of the Feb. 2 coal ash spill on the Dan River has mushroomed into a multifaceted probe of both Duke Energy and the Department of Environment and Natural Resources, in the wake of allegations about too-friendly relationships and lax regulation. Duke and the DENR are dealing not only with cleanup work at the Dan River site, but also with subpoenas regarding other coal ash sites and a federal criminal probe of their relationship.
Gov. Pat McCrory, who worked at Duke for 28 years, denied Friday that he had had any involvement in the state’s decision to preempt environmental groups’ lawsuits by suing and settling with Duke itself, in what critics called a sweetheart deal. After the Feb. 2 ash spill, DENR asked a court to delay ruling on the settlement.
Subpoenas released last week order 18 state water-quality officials to testify before a federal grand jury on communications with Duke as well as any payments and gifts from the company. The DENR was subpoenaed for ash-related records on all 14 of Duke’s coal plant sites. Duke said it also received a subpoena.
Duke Seeks 300 MW Solar Capacity, in Large Projects
Duke Energy is soliciting 300 MW of new solar capacity in its Carolinas and Progress territories, which it wants in service by the end of 2015. The solicitation, which would almost double Duke’s solar capacity in the state, allows flexibility to offer power and associated renewable energy certificates, and/or a turnkey arrangement in which Duke would take ownership. The request for proposals targets projects larger than 5 MW that are already in Duke’s transmission queue.
Strata Solar, the largest solar developer in the state, might build a facility in Wayne County near Fremont, and has obtained an ordinance from Fremont that would allow it. A permit application has yet to be made, with details of the project, but Strata typically builds 5-MW farms on 40 to 50 acres.
Anderson County, South Carolina, officials approved the outline of an incentive plan for Duke Energy to build a 750-MW natural gas combined-cycle unit, of which North Carolina Electric Membership Corp. would own 100 MW. The plant would be at the site of Duke’s W.S. Lee Steam Station, where the company already plans to shut two existing coal-fired units and convert one to gas. Plans for the new unit are not final, and county officials have yet to vote on details of the incentives, which include 40 years of tax breaks.
The closing of an Ormet aluminum factory, with its 700 jobs, last year has become a significant issue in the gubernatorial race as critics question whether Gov. John Kasich did what he could to get lower electricity rates for the plant from American Electric Power. Democratic gubernatorial hopeful Ed FitzGerald called on Kasich to support legislation granting the governor authority to override the Public Utilities Commission, which refused to increase the rate subsidy that Ormet had already been receiving. Kasich said it was not his place to “tell the PUCO what to do.”
The Ohio Supreme Court said American Electric Power does not have to refund customers $368 million for charges ruled improper in 2011. The ruling involves the court’s 2011 decision that AEP bills included improper charges. The consumer advocates and business group that challenged the charges did not ask initially for a stay of the charges. Had they done so, AEP would not have been allowed to collect until the legality of the charges had been determined, the high court ruled.
FirstEnergy utilities in Ohio will spend a total of about $750 million this year for reliability and infrastructure projects, a significant increase over 2013’s expenditures.
Ohio Edison said it would invest more than $475 million, $344 million of it to be spent by FirstEnergy unit American Transmission Systems Inc., including the start of construction on a new 100-mile, 345-kV line from the Bruce Mansfield plant to the Cleveland area. Other Ohio Ed work includes new substations and enhanced remote-control technology, as well as ongoing vegetation management, which is common to all the FE utilities’ programs.
The Cleveland Electric Illuminating unit will invest about $176 million in a variety of projects, including new substations and installation of voltage regulating equipment. Toledo Edison will spend nearly $100 million on a new substation, upgraded transmission and distribution lines, additional transformers and more.
The Public Utilities Commission introduced a website, Energy Choice Ohio, to help consumers shop for electricity and natural gas. To use the new site, which the PUC says is more interactive than a former site, customers must first determine what rate they are paying.
Gov. Tom Corbett nominated Robert Powelson to another term on the Public Utility Commission, where he has been chairman since February 2011. Powelson’s leadership “has been crucial to developing our robust electric retail marketplace, which now is ranked number two in the nation,” Corbett said in the announcement. Powelson, whose current term expires April 1, was appointed to the PUC in 2008 by Gov. Ed Rendell.
PUC Opens Case to Study Variable-Rate Seller Rules
Flooded with complaints about extraordinary bill spikes in the recent extreme-cold events, the Public Utility Commission has opened an examination of rules governing variable-rate electric products. The PUC wants input on what information retail suppliers must disclose to customers, some of whom were shocked by bills that at least doubled and rates that were much higher than utility default rates.
The Public Utility Commission proposed changes to the Alternative Energy Portfolio Standards Act to revise net metering and interconnection rules and reporting requirements. The changes include standards for qualification of large distributed generation systems as customer-generators; addition of a process for getting PUC approval for net metering alternative energy systems with nameplate capacity of 500 kW or greater and clarification of virtual net metering language.
Nuclear waste storage casks at Dominion’s North Anna nuclear plant that shifted during the 2011 central Virginia earthquake can stay where they are, the Nuclear Regulatory Commission staff said. The casks moved slightly but suffered no damage and are still spaced sufficiently apart, the company said.
Dominion told the federal Bureau of Ocean Energy Management that it would bid in an auction to lease offshore wind development acreage off Ocean City, Md. The 80,000-acre lease site has potential for up to 1,450 MW, the company said. Dominion already won the bidding for 113,000 acres off the Virginia coast, and it said the Maryland acreage’s proximity to that leased area and to the port at Hampton Roads would offer economies of scale for development.
Appalachian Power plans a $50 million upgrade in Tazewell and Buchanan counties in western Virginia, with all work scheduled to be completed in 2017. Work involves building a new substation and improving others, adding a 138-kV line and upgrading another line to 138 kV.
APCo Sets $80 Mil Project To Upgrade Southern Area
Appalachian Power will seek regulatory approval for an $80 million upgrade to transmission infrastructure in McDowell County in the southern part of the state, with work expected to be finished in 2017. The American Electric Power unit’s project includes removing some 88-kV transmission and upgrading other 88-kV lines to 138 kV.
Duke Energy’s earnings were up for 2013, with profits of $2.7 billion producing earnings of $3.76 a share, compared with $1.8 billion and $3.07 per share the year before, the company announced Tuesday.
The company saw revenue growth from its regulated businesses, especially from territories added in North and South Carolina and Florida as a result of its merger with Progress Energy. Duke now controls utilities with more than 7 million customers in North and South Carolina, Florida, Ohio, Indiana and Kentucky.
Fourth-quarter earnings were $688 million, or 97 cents per share, compared to $435 million, or 62 cents per share, from the year before.
Notable, however, was a substantial decrease in revenue from its Commercial Power unit, which includes 6,800 MW of merchant generation and a retail sales subsidiary. It produced income of $15 million in 2013, compared to $93 million the year before.
Those results underscored the company’s announcement the day before the earnings were released that it was withdrawing from the merchant generation business in the Midwest. It warned that it expects to sell the 13 plants at below book value, resulting in a likely pretax charge of $1 billion to $2 billion in the first quarter of this year.
Its regulated utilities showed a fourth-quarter income of $607 million, compared to $498 million in the fourth quarter of 2012, driven by lower operating and maintenance costs, savings from the Progress merger and customer rate increases.
“We were forecasting a stronger third and fourth quarter as a result of some of the regulatory approvals, and we were able to close strongly,” Good said.
Tx Investments Drive PSEG Earnings
A renewed concentration on its regulated businesses, including transmission system operations, helped Public Service Enterprise Group produce operating earnings of $1.3 billion, or $2.58 per share, for 2013, compared to $1.23 billion, or $2.44 per share, for 2012 – an increase of nearly 6%.
Its fourth-quarter operating earnings were $248 million, or 49 cents per share, compared to $207 million, or 41 cents per share.
The company’s 2012 results had been hurt by the more than $250 million it spent on repairs after Hurricane Sandy. The 2013 results also reflected a significant increase in revenue as a result of transmission investments.
After investing $1.7 billion to upgrade its network in 2013, transmission now represents about 36% of PSEG’s rate base, up from 28% at the end of 2012.
CEO Ralph Izzo noted that the company has received authorization from PJM to begin construction on a $1.2 billion project to build a double-circuit line in the Bergen-Linden Corridor in northern New Jersey. (See Planners Choose $1.2B PSEG Short Circuit Fix.)
The company’s 2014 results should benefit from FERC’s approval of a $171 million increase in its annual transmission revenue, effective Jan. 1.
Like many utilities this year, PSEG is warning that operating earnings from its power generation operations will likely decline. PSEG’s wholesale power business reported earnings of $710 million in 2013, but the company predicts that figure to drop to between $550 million and $610 million for 2014.
Two members of the Federal Energy Regulatory Commission last week balked at former Chairman Jon Wellinghoff’s campaign to raise awareness of the threat of sabotage of the electric grid, saying it could result in copycat attacks and wasteful spending. Separately, the head of the North American Electric Reliability Corp. said he opposed mandatory standards on physical security as expensive and unworkable.
Commissioners John Norris and Philip Moeller made statements at last week’s meeting in response to news articles earlier this month reporting on Wellinghoff’s concerns about the April 2013 sniper attack on a PG&E substation near Metcalf, Calif. The former chairman called the attack “the most significant incident of domestic terrorism involving the grid” to date. (RTO Insider provided an account of the attack based on a presentation at PJM’s Grid 20/20 conference in November. See Substation Saboteurs ‘No Amateurs’.)
Congressional Inquiry
Following the articles, Senate Majority Leader Harry Reid and three fellow Democrats wrote a letter to acting FERC Chair Cheryl LaFleur and NERC CEO Gerry Cauley asking them to determine whether reliability regulations were needed to address the physical security of “critical substations and other essential functions.”
In a letter to Reid Feb. 11, LaFleur said that FERC had joined NERC, the Department of Homeland Security, the Department of Energy and the FBI in an outreach campaign to utilities, states and law enforcement agencies, including a detailed briefing about the Metcalf incident. “This approach has resulted in improvements being implemented more quickly and more confidentially than a mandatory regulation could have accomplished under our existing authority,” she wrote.
LaFleur added, however, that she had directed FERC staff to work with NERC to determine whether a mandatory reliability standard is needed “to protect against physical attacks on our electric infrastructure.”
In his own response, NERC’s Cauley said he opposed a mandatory standard. “There are more than 55,000 substations of 100 Kv or higher across North America, and not all those assets can be 100% protected against all threats,” Cauley wrote. “I am concerned that a rule-based approach for physical security would not provide the flexibility needed to deal with the widely varying risk profiles and circumstances across the North American grid and would instead create unnecessary and inefficient regulatory burdens and compliance obligations.”
Cauley summarized NERC’s “defense-in-depth” philosophy, which includes simulation exercises such as NERC’s two-day drill last November. (See Grid Exercise `Like a Disaster Movie’.)
At last Thursday’s open meeting, Commissioner Moeller read a brief statement warning that “highlighting any real or perceived vulnerabilities and sharing specific security information or responsive actions may inadvertently promote the prospect of additional copycat attacks.”
Commissioner Norris had far more to say, warning that “elected officials and our former colleague seem to be calling for significant measures specifically geared toward erecting various physical barriers to our grid infrastructure.”
“I am concerned,” he said, “that such actions are a 20th century solution for a 21st century problem.”
Norris said three utilities that met with him recently indicated they may spend more than $500 million on physical barriers and increased security measures around transformers and substations.
PG&E said Feb. 10 it plans to install opaque walls, advanced camera systems, enhanced lighting and additional alarms at multiple substations as a result of the attack. Although it did not place a cost estimate on the improvements, it said it would likely seek a rate increase to fund them.
Norris said making such investments nationwide could cost billions — money he said would be better spent on “a multi-functional, intelligent grid that is resilient and capable of mitigating multiple kinds of threats.” He noted that in addition to potential saboteurs, the grid also faces threats from cyber-attacks, geomagnetic disturbances, electromagnetic pulses and natural disasters.
Metcalf Attack
At least two gunmen were believed involved in the attack on PG&E’s Metcalf 500/230 kV substation near San Jose about 2 a.m. April 16. The shooting occurred minutes after the suspects were believed to have cut underground fiber optic cables a half-mile from the substation, briefly knocking out phone and 911 service in the area.
The shooting caused more than $15 million in damage and prompted the California Independent System Operator to issue an alert asking residents in the region to cut their electricity use. The substation was out of service for nearly a month.
The incident was strikingly similar to a scenario Wellinghoff had outlined in 2012 in an interview with Bloomberg News. Transformers are often custom built and can take 18 to 36 months to replace, Wellinghoff said.
The recent news accounts quoted Wellinghoff reporting that investigators found that the shell casings discovered outside the substation were wiped off to prevent fingerprint detection. Wellinghoff also said military experts spotted small rock piles outside the substation that might have been left earlier to mark the best firing positions.
While Wellinghoff characterized the incident as “terrorism,” the FBI has not agreed with such a characterization.
“Based on the information we have right now, we don’t believe it’s related to terrorism,” an FBI spokesman told The Los Angeles Times, noting that no one has been arrested in the case. “Until we understand the motives, we won’t be 100% sure it’s not terrorism.”
LaFleur: Change FOIA
Unlike Norris and Moeller, LaFleur did not criticize Wellinghoff’s actions in raising the alarm about the attack.
But she told reporters after the meeting she agreed with her colleagues that “the resilience of the grid needs to be viewed broadly.”
She said FERC would seek to “maximize existing authority before talking about” seeking more powers. However she said Congress could help security efforts by amending the Freedom of Information Act to exempt sensitive information regarding grid vulnerabilities and threats from disclosure.
In her letter to Reid, she added: “Congress should consider designating a federal department or agency (not necessarily FERC) with clear and direct authority to require actions in the event of an emergency involving a physical or cyber threat to the bulk power system. This authority should include the ability to require action before a physical or cyber national security incident has occurred.”
Senators’ Letter
The letter from Reid, which was signed by Ron Wyden (D-Ore.), Al Franken (D-Minn.) and Dianne Feinstein (D-Calif.) expressed concern “that voluntary measures may not be sufficient to constitute a reasonable response to the risk of physical attack on the electricity system. While it appears that many utilities have a firm grasp on the problem, we simply do not know if there are substantial numbers of utilities or others that have not taken adequate measures to protect against and minimize the harm from a physical attack. A chain is only as strong as its weakest link.”
Unlike a chain, however, the grid is designed to remain functional despite the loss of individual assets.
“We should look to further deployment of phasor measurement units, wide-area management systems and enhanced situational awareness,” Norris said. “Furthering efforts in the development and deployment of microgrids and smart grid technology will also greatly assist in addressing grid resiliency.”
WASHINGTON — Two members of the Senate Energy committee cited PJM’s struggles during January’s arctic cold to support their concerns about the impact of the Environmental Protection Agency’s pending greenhouse gas regulations.
Sens. Joseph Manchin (D-W.Va.) and Lisa Murkowski (R-Alaska) said they fear EPA’s CO2 limits on existing generators could threaten reliability by forcing coal plant closures in addition to those forecast by 2015 due to EPA’s Mercury and Air Toxics Standards (MATS).
“I was told we were within 700 megawatts of the whole PJM system coming down [during the January cold spells],” Manchin said. “That’s unconscionable.”
Murkowski said that for “one key grid” — which she later identified as PJM — “89% of coal slated for retirement next year was called upon during the cold spell.”
“A hope and a prayer is not the way we should be operating,” she added.
Voltage Reduction, Not Collapse
PJM spokesman Ray Dotter said Manchin’s reference was to the peak hour on Jan. 7, when the unexpected loss of 700 MW of generation — or a similar jump in demand — would have required a voltage reduction. “While a voltage reduction is a serious step, it is a tool used from time to time when power supplies are tight, and it is unnoticed by most consumers,” PJM said in a statement.
In response to Murkowski’s comment, Dotter acknowledged that PJM called a maximum emergency generation action to mobilize all available resources — including units slated for retirement and voluntary demand response — several times in January.
“The experience in January reinforces the value of PJM’s capacity market rule changes to encourage more annual [demand response] resources and demonstrates the value of load management to system reliability throughout the year,” PJM said.
Despite the pending retirements, the RTO said it was confident it will have the resources necessary to ensure reliability. It cautioned that “operating reserves will narrow because excess resources will be retired, and energy prices could be more volatile.”
World’s Largest Fuel Switch
NYMEX Forward Curves for the PJM Western Hub (Source: PJM Interconnection, LLC)
At PJM’s General Session after the NARUC conference, officials briefed stakeholders on what they called the “world’s largest fuel switch,” which will see the RTO’s coal- and gas-fired generation swap market shares, with coal capacity dropping to 50 GW from more than 70 GW while gas grows to 70 GW from more than 50 GW.
Andy Ott, PJM executive vice president for markets, presented a projection showing PJM’s installed generation dropping by a net of almost 3,500 MW (2%) by 2017, with 9,500 MW in additions and almost 13,000 MW in retirements.
The presentation included a look at the NYMEX forward curves for the PJM Western Hub monthly peak contract. Traders last month boosted prices for the winter 2014, 2015 and 2016 forwards, but summer prices remain below those that traders were paying last year (see chart).
“I think the forward curves are understated,” Ott said. “People haven’t realized how much net change in generation we are going to have.”
The Federal Energy Regulatory Commission was within its rights to approve PJM’s controversial capacity market rule changes in 2011, a somewhat reluctant federal appeals court ruled Feb. 20, rejecting challenges from New Jersey, Maryland and others. The court also upheld FERC’s approval of changes opposed by the generator group PJM Power Providers.
The US Court of Appeals for the 3rd Circuit upheld FERC’s decision approving the elimination of an exemption for state-mandated resources from the capacity market’s minimum offer price rule (MOPR), but said it found the commission’s actions “more than mildly disturbing.”
By earlier endorsing PJM’s rules that included an exemption for state-mandated supplies, the court said, “FERC would allow sovereign states and private parties to be drawn into making complex and costly investments, only to later pull the rug out from under those who were persuaded that the exemption was somehow real. That FERC has done so based on little more than the claim that the agency had an ‘ah ha’ moment when foreseeable outcomes approached fruition only makes matters worse.”
Nevertheless, the court upheld FERC’s ruling, saying the standard needed to find FERC’s action arbitrary and capricious, “is a high bar indeed, and many agency actions worthy of condemnation are not so deficient that they can be said to cross it. Such is the case here.”
Judging by that standard, the court said, the commission advanced adequate rationale for its “about-face.” Speculation that states would structure contracts to substantially suppress prices “has become reality,” the judges ruled. “As such, it cannot be said that FERC acted without substantial evidence.”
The case, New Jersey BPU v. FERC (No. 11-4245, et al), arose after New Jersey and Maryland instituted programs to procure 2,000 MW and 1,800 MW, respectively, of new generation to be bid into PJM capacity market auction at prices below the Cost of New Entry (CONE).
PJM concluded the state initiatives interfered with the capacity market’s ability to send competitive price signals. New MOPR provisions were set that limited state-sponsored generation to certain characteristics, including that it did not give preference to new resources over existing ones or restrict the type of resource that could participate. The state programs had sought new gas-fired capacity, which PJM specifically said would not be exempt from the MOPR.
The states and consumer advocates protested, arguing states should have the right to select capacity based on fuel diversity, environmental benefits or economic development.
The court rejected the states’ argument that FERC was usurping their rights by eliminating the exemption for state-sponsored resources. “[W]hat FERC has actually done here is permit states to develop whatever capacity resources they wish,” the court said, “and to use those resources to any extent that they wish, while approving rules that prevent the state’s choices from adversely affecting wholesale capacity rates. Such action falls squarely within FERC’s jurisdiction.”
Regina Davis, spokeswoman for the Maryland Public Service Commission said the PSC was disappointed in the ruling and had not made a decision concerning an appeal.
Also challenging the FERC ruling was the American Public Power Association, but the court said its concerns were made moot by later PJM and FERC actions. In 2013, PJM parties worked out a plan, which FERC approved, that assuaged many concerns of load-serving entities like public power utilities that self-supply. It did not reinstate the previous guaranteed market clearing for self-supply resources, but it exempted self-supply from price mitigation subject to showings that the self-supply will not set the market-clearing price.
APPA was also dismayed by the ruling. The MOPR changes at PJM “partially redressed” public power’s problem, but the negotiated provisions are “not of the same quality” as the original MOPR and do not constitute “a done deal,” APPA Vice President Sue Kelly said yesterday.
The provisions are the subject of rehearing petitions at FERC, she said. To APPA, a fierce critic of the capacity market, the court’s handling of its issue illustrates how “nothing is ever safe” from “endless litigation” and “years of stakeholder process.”
The P3 group, which originally had challenged several MOPR revisions, had some of its concerns addressed later by further changes to the rule. Two of its concerns remained for the court, however: the policy of basing the calculation for energy and ancillary services offsets on the zone with the highest revenues, and the policy of exempting resources from the MOPR once they have cleared one capacity auction, instead of three auctions.
The court rejected the generators’ arguments. About the calculation issue, it said “FERC has articulated legitimate reasons for finding PJM’s preferred method for calculating energy and ancillary services offsets just and reasonable, and that is all it is required to do.”
The Federal Energy Regulatory Commission will hold a day-long technical conference April 1 to discuss operational and market issues raised by this winter’s extreme cold, which exposed vulnerabilities in the grid’s increasing reliance on natural-gas fired generation.
Acting FERC Chair Cheryl LaFleur announced the conference last week, saying it would focus in part on the experience in PJM, which last month called on demand response, a voltage reduction and voluntary appeals for conservation to avoid rolling blackouts in the face of record demand and large numbers of generator outages. (See Pony Up! Members Express Anger over High Prices, Uplift Allocation.)
LaFleur said an agenda for the conference has not yet been completed.
Much of the consternation at the NARUC winter conference concerned EPA’s planned CO2 emission limits on existing generating plants (Section 111(d) of the Clean Air Act).
The regulations, expected in June, could add 60 to 100 GW in coal retirements beyond those already expected from current air and water regulations, according to the Edison Electric Institute.
Janet McCabe, EPA’s acting assistant administrator for the Office of Air and Radiation, who had addressed NARUC’s annual conference in November, was back again to provide an update on the agency’s outreach efforts.
EPA Listening Sessions
McCabe said EPA has held more than 200 meetings through January to listen to industry and state regulators’ concerns about the pending regulations.
“What we’ve been hearing: Reliability is key. Affordable energy is key. Flexibility is absolutely critical but states don’t want to be handed a blank sheet of paper. They want guideposts,” she said.
McCabe said the proposed regulations will reflect those concerns while seeking to minimize stranded assets and acknowledging differences among states in their fuel supplies and the energy intensity of their economies.
EPA’s charm offensive won praise from acting FERC Chair Cheryl LaFleur and Jon McKinney, a member of the West Virginia Public Service Commission. “In 30 years in the chemical industry and eight years as a commissioner, it’s the first time I’ve worked with EPA so closely,” McKinney said.
One of the biggest questions is whether EPA will set limits by state or establish regional caps.
ISO/RTO Council Proposal
In January, the ISO/RTO Council proposed a “Reliability Safety Valve” similar to that adopted by EPA in the Mercury and Air Toxics Standards to ensure the GHG rule includes a process to assess and mitigate reliability impacts. It also proposed allowing states the option of meeting their obligations through regional efforts whose efforts could be coordinated, and results measured, by RTOs such as PJM.
LaFleur said the regulations may require PJM and other regional transmission operators to modify their rules to accommodate state or regional plans for achieving emission cuts. “If we work together across state lines there might be an upside to help some of these states that have challenges,” she said.
“There’s lots of precedents already for [EPA] working across state lines,” McCabe said. “There’s no doubt that the program will be able to accommodate that.”
Moeller said he feared the potential for conflict between state implementation plans and interstate energy markets. Asked how FERC might referee such conflicts, he responded: “I think it’s a little early for [FERC] to be considering our role.”
Jurisdiction Questions
Colorado Public Utility Commission member Joshua Epel questioned how EPA planned to enforce the regulations. “You could be trying to bind state PUCs, and frankly I don’t think you have the authority to do that,” said Epel, who said the rules should allow a continued role for Colorado-mined coal. “We have an enormous challenge. We’ll be working together, but sometimes we’ll be slugging it out. That’s just the nature of what this is going to be.”
Joe Goffman, senior counsel in EPA’s Office of Air and Radiation, said “maybe it’s the regional NARUC entities that are best positioned … to provide a platform for” compliance.
PJM wants to change the way virtual trades pay for uplift, replacing the current unpredictable charges with a flat per megawatt fee and assessing them for the first time on up-to congestion trades (UTCs).
PJM UTC Transactions Total Volume: Jan 2010 – Dec 2013 (Source: PJM Interconnection, LLC)
The changes would create new dynamics for financial marketers, who have increased their trading in UTCs eight-fold since 2010 while increment offers (INCs) and decrement bids (DECs) have dropped by two-thirds.
PJM outlined its plans yesterday to the Energy Market Uplift Senior Task Force (EMUSTF).
Monitoring Analytics, PJM’s Independent Market Monitor, called for assessing uplift charges on UTCs in its 2012 State of the Markets Report.
Under orders from the Federal Energy Regulatory Commission, PJM conducted a new analysis that concluded that UTCs — like INCs and DECs — affect generating unit commitments and thus can contribute to uplift costs.
PJM Analysis
PJM re-cleared its day-ahead energy market for four days in December and concluded that INCs and DECs resulted in a change of 3.1% in total unit commitments while UTCs were responsible for a change of 2.3%.
PJM said the virtual transactions should be assessed charges although it is impossible to quantify their exact impact on those charges.
“Similar to INCs and DECs, whether or not UTCs drive a more optimal solution in the Day-Ahead Energy Market will change on a daily basis and a precise determination of the direction and impact on resource commitment and dispatch by UTCs is virtually impossible due to the complexity of the Day-Ahead Energy Market and the interactions of the various different types of transactions,” PJM wrote in a report filed with FERC (ER13-1654).
The analysis found that INCs and DECs resulted in increased unit commitments. UTCs caused the de-commitment of certain units and their replacement with other units, “consistent with the energy neutrality of UTCs,” PJM said.
“However, there is not always a one-to-one tradeoff between committed and de-committed units when UTCs are removed, and the cost of the units being swapped are not always identical,” PJM wrote. “In some cases UTCs may be driving the commitment of lower cost resources in the day-ahead energy market because they are in the counterflow direction of transmission constraints and are therefore relieving congestion. In other cases the opposite will occur, and UTCs will impose forward flow on a facility in the day-ahead energy market and cause increased congestion and out-of-merit commitment and dispatch for constraint management.”
Market Monitor Analysis
In September, Market Monitor Joseph Bowring released an analysis that he said proved UTCs increase shortfalls in Financial Transmission Rights funding and disproved UTC supporters’ contention that the trades help price convergence.
While PJM says it is impossible to quantify the impact of UTCs on uplift, Bowring provided precise figures.
Over a five-day sample in May, Bowring said, FTR funding had a deficit of $4.4 million with UTCs versus a surplus of $22,000 with UTCs removed — a difference of $4.6 million.
In its 2012 State of the Market report, the monitor called for eliminating UTC transactions or making them responsible for day-ahead and balancing operating reserve charges.
The monitor said the RTO deviation rate for 2012 would have been reduced by 59% percent if UTC transactions had been included in the calculation of operating reserve charges.
PJM’s Plans
At Wednesday’s EMUSTF meeting, PJM Vice President of Market Operations Stu Bresler said the RTO will propose a flat per megawatt charge for all virtual transactions and eliminate the current variable allocation on INCs and DECs, “taking away the risk of unknown and volatile charges on the back end.”
PJM’s Dave Anders said the RTO will begin discussing the specifics of a future cost allocation with stakeholders in “Phase 2” of the task force’s work, which he said should begin in the “next month or two.”
UTCs’ use has exploded since late 2010, when PJM removed the requirement that UTCs make transmission service reservations — thus removing them from a share of uplift charges. Trading in INCs and DECs declined over the same period because of what PJM called the “strong disincentive” caused by the unpredictable uplift charges they are assessed.
Deviation charges per cleared MWh for INCs and DECs (Source: PJM Interconnection, LLC)
In 2013, INC and DEC transactions in eastern PJM paid a rate of $0.02/MWh to $33.02/MWh for deviations between the Day Ahead and Real-Time energy markets, with a mean of $3.20/MWh. Such trades in the west paid $0.02/MWh to $16.43.MWh, with a mean of $1.56/MWh. (See chart.)
“At the time rules for INCs and DECs were put in place, UTCs were not used in the speculative manner in which they are today and therefore were not included in the allocation of such charges,” PJM wrote. “However, given how the use of UTCs has evolved, it is evident, based on the fact that UTCs can shift the flow of power on the system, that they also can impact the resource commitment and dispatch of the system and consequently should be allocated a share of the applicable costs in addition to INCs, DECs and other bid and offer types that have similar impacts on the power system.”
Some stakeholders at yesterday’s meeting protested PJM’s reference to UTCs in the report as a “free transaction,” noting that they do pay administrative charges.
High-cost gas-fired generators will be able to set PJM market clearing prices above $1,000/MWh for the remainder of the winter, the Federal Energy Regulatory Commission ruled.
The commission granted PJM’s request for a waiver of PJM’s $1,000 offer cap through March 31, setting the stage for a contentious stakeholder debate over the long-term fate of the cap.
FERC’s order (ER14-1145) came over the objections of consumer advocates, state regulators and others, who said allowing the RTO’s most inefficient generators to set clearing prices would provide a windfall to the vast majority of generators with costs well below $1,000.
The commission sided with PJM and generators, who said the high prices should be reflected in clearing prices to provide signals for new entrants and allow market participants to hedge their risks. (See Price Cap Ruling Could Reverberate for Years.)
The order supersedes the commission’s Jan. 24 ruling (ER14-1144) allowing make-whole payments for generators with operating costs above the cap. That order allowed PJM to fund the make-whole payments through uplift charges, which cannot be hedged.
“By paying an uplift, PJM is in effect paying one price for energy dispatched through the market (e.g. $1,000), and a second higher price (e.g. $1,200) for the resource dispatched out-of-merit (while treating the latter in the dispatch stack as if it had a bid of $1,000),” the commission ruled. “This would not be consistent with longstanding Commission precedent. The Commission has previously found that `[p]ayments made only to individual resources and recovered in uplift fail to send clear market signals’ and that those resource costs `should be reflected in transparent market prices whenever possible.’”
PJM said the $1,000 cap was five to seven times higher than the marginal cost of production when the commission approved it as a market power mitigation measure.
“We did not anticipate that, when the $1,000/MWh bid cap was adopted, it would prevent marginal cost bidding,” the commission said. “Presently, however, the $1,000/MWh bid cap is preventing competitive marginal cost bids and resulting competitive prices that are needed to balance supply and demand.”
The commission dismissed concerns that lifting the cap would allow gaming, noting that generators will have to provide proof of their costs to the Independent Market Monitor. It ordered the Monitor to file a report by the end of April identifying the number of hours when clearing prices exceed $1,000, the resulting prices and total energy costs.
In addition, FERC’s enforcement staff will be monitoring the market for instances of market manipulation, the commissioners said.
The ruling will have no practical impact if natural gas prices remain at normal levels for the remainder of the winter. But if another cold snap sends prices above $100/mmBtu — as it did at some locations servicing PJM generators in January — costs to load could increase dramatically, if briefly.
FERC rejected calls that it lift the $1,000 price cap in the neighboring NYISO, which asked FERC for the more limited relief of make-whole payments funded through uplift (ER14-1138). A $1,000 cap also remains in place for MISO.
“The NYISO order is distinguished from the instant case because NYISO did not request that the marginal costs be reflected in clearing prices,” the commission said.
