A novel project: Energy generated from wind turbines (in Wyoming) powers compressors (in Utah) that inject high-pressure air into salt caverns underground. The compressed air is stored for high-demand hours.
Duke Energy is joining a novel $8 billion project using Wyoming wind energy and Utah salt mines to provide power to Los Angeles.
Duke-American Transmission Co. (DATC) is one of four companies proposing the project, which would be the first time underground compressed-air storage would be used on such a scale in the U.S.
“This project would be the 21st century’s Hoover Dam — a landmark of the clean energy revolution,” said Jeff Meyer of Pathfinder Renewable Wind Energy, one of the four companies involved.
Meeting California Renewable Goals
The project is one of about 200 plans California officials will consider to help it reach its renewable-energy goals. Duke and the other companies said they would be submitting the proposal in early 2015.
The project would start with a $4 billion, 2,100-MW wind farm north of Cheyenne, Wyo., to be built by Pathfinder Renewable Wind Energy. Power from the facility would be sent to an energy storage facility near Delta, Utah, on a $2.6 billion, 525-mile transmission line to be built by DATC.
In Utah, four massive caverns — each a quarter-mile high and 290 feet in diameter — would be carved out of underground salt formations.
At times of low demand, electricity from the wind farm would power compressors that would inject high-pressure air into the caverns.
At times of high demand, the high-pressure air, combined with a little natural gas, would power eight generators. The $1.5 billion facility, to be built by Pathfinder, Magnum Energy and Dresser-Rand, would be rated at 1,200 MW.
An existing 490-mile transmission line would deliver the power through Utah, Nevada and California to Los Angeles.
Intermittent Wind
(Source: Dresser-Rand)
The project is intended to address the challenge of matching wind’s variable output with energy usage patterns.
California’s wind farms tend to generate most of their power in the evening, dropping off when energy demand reaches its peak. Wyoming wind, by comparison, tends to increase later in the day.
Dresser-Rand designed and built the first facility using compressed-air energy storage (CAES) in Alabama; the facility is linked to a coal-fired generating station. The 110-MW unit went into operation in 1991, and boasts a 96.7% reliability record in generation mode. There is one other operating CAES facility in Huntorf, Germany.
If the project goes forward, one of the first jobs will be excavating the caverns, using a process called solution mining. Magnum Energy, which has excavated other storage caverns, said it would inject water into the underground salt formations, dissolving the salt and pumping the salt solution to the surface, where it would be dried. Underground caverns have long been used for oil and natural gas storage.
The project, which is not expected to be completed until 2023, would be subject to numerous state and federal regulatory approvals, none of which has been applied for yet.
Exelon Generation is adding another 2,000 MW of fossil generation to its fleet in Texas, which will bring the company’s total generation in ERCOT to nearly 6,000 MW.
The company announced Monday it was investing more than $500 million in four gas and two steam turbines to build combined-cycle plants at two of their existing sites.
General Electric H-Class Turbine (Source: BusinessWire)
In addition to using the most fuel-efficient technology, the plants will be air-cooled, rather than water-cooled, a big plus in drought-threatened Texas. The turbines will be General Electric H-class models, which GE says will allow more than $8 million in fuel savings per turbine a year.
French company Alstom is providing the heat recovery steam generators. Earlier this year, GE agreed to buy the power arm of Alstom for $16.8 billion.
It will be the first use of the new GE turbines in the U.S.
“What we see is a clean-energy future that includes this kind of new technology, which uses little water and produces few emissions while generating electricity at a very low cost,” said Ken Cornew, president and CEO of Exelon Generation.
The new combined-cycle plants are to be built at Exelon Generation’s Wolf Hollow site in Grandbury, southwest of Fort Worth, and the Colorado Bend plant in Wharton County, southwest of Houston.
Exelon Generation currently has six generating stations in Texas with a combined output of about 3,700 MW. It has wind farms generating an additional 281 MW, for a total of nearly 4,000 MW.
The two new plants will boost that total to nearly 6,000 MW. Exelon said it would start construction of both plants in 2015 and expects both to be in service by 2017.
Exelon needs $580 million in additional revenue annually to keep its Illinois nuclear fleet in operation, Senior Vice President Kathleen Barron told the Illinois Commerce Commission last week.
Exelon has been saying for months that unless pricing for the output of its Illinois nuclear stations improves, it may need to shut them down. Barron said the company figures it needs about $6 more per MWh for continued operation. That would translate to rate increases of about 8% in Chicago and more downstate, where prices are cheaper.
And even that might not do it. “While a $6/MWh payment or even less would be sufficient for some units, $6 may not be enough for others,” the company said in a statement. “Each of our 11 nuclear units in Illinois has a different cost structure and different requirements.”
Barron’s comments are part of a national campaign by Exelon to gain credits for its carbon-free output, and cut or reduce the federal wind production tax credit, to let its plants compete. Company lobbyists and executives have been delivering a consistent message since the spring. (See Exelon in Lobbying Push to Save Ill. Nukes.)
Barron said the result of closing the nuclear stations would be significant for Illinois. “If the units at risk of closing today — representing 43% of the state’s nuclear generation — retire, they cannot be mothballed and later brought back online,” Barron said. “Together, they represent more than 30 million metric tons of avoided carbon emissions, given that they will need to be replaced with fossil generation to provide the around-the-clock electricity needed to serve customers in the state.”
Dominion Virginia Power is starting a $2 billion project that will underground 4,000 miles of outage-prone lines by 2026.
The target represents about 11% of the company’s overhead distribution lines, and placing them underground should result in increased reliability, the company said. About a third of the company’s 58,000 miles of distribution lines are now underground.
It said it will spend about $175 million a year moving the lines. The company is expected to file an application for a rate increase to pay for the project with the Virginia State Corporation Commission by the end of October. The rate increase would go toward the project, it said.
South Carolina Official Upset Duke Hasn’t Removed Ash Yet
A South Carolina Public Service commissioner said he thought Duke Energy was already removing stored coal ash from its sites in the state. He was surprised to learn it hasn’t started yet.
“I think it’s somewhat of a surprise to this commission that no ash is being removed because this has been an ongoing situation that we’ve heard about and talked about,” Commissioner G. O’Neal Hamilton said. “We’ve seen reports of trucks moving in North Carolina and I assumed that was happening here and it’s a little disappointing.”
The issue arose after environmentalists said that the company’s W.S. Lee Steam Station has coal ash lagoons that are leaking toxins into the surrounding area. Duke said it will present the commission with plans for the removal by the end of the year. Duke is converting the plant to burn natural gas. A Duke spokesman said plans are being made to remove coal ash from a number of sites in North Carolina as well, but they have not yet been implemented.
Ralph Rogers, Tennessee Valley Authority’s top lawyer, is retiring at the end of the year. Rogers started with the federal authority in 1979 and became TVA’s senior litigation attorney and ethics officer. He was the highest paid attorney in TVA history, making $1.9 million last year and $2.5 million the year before. High executive salaries at TVA have drawn fire from former Knoxville Mayor Victor Ashe, who said “most East Tennessee attorneys do not make a quarter of that amount (paid to Rodgers) in one year.”
Under the corporate-like board structure adopted for TVA by Congress in 2006, pay levels for the general counsel and other top officers at TVA have risen significantly over the past decade to more closely align with investor-owned companies rather than the government-level pay grades used by TVA in the past.
Public Service Electric and Gas started construction of a 10-MW solar plant on a former garbage dump in New Jersey, the latest and largest system of solar arrays the company is building. The project will sit atop a capped dump in Bordentown.
It’s part of a state-wide effort to use brownfields and under-used industrial sites to build solar plants to deliver energy to the grid. The company is planning to spend $247 million on this and similar projects. It is eying plans to build an even larger solar plant on another former dump in New Jersey.
Grid operators demonstrated resiliency during January’s polar vortex but more needs to be done to prepare for future cold spells, the North American Electric Reliability Corporation said in a report released today.
All-time Winter Peaks vs. Polar Vortex Loads by Pct. (Source: NERC)
NERC’s Polar Vortex Review noted that only one balancing authority shed load despite the fact that many areas in the Midwest, South Central and East Coast experienced temperatures 20 to 30 degrees below normal. (South Carolina Electric and Gas (SCE&G) dropped less than 300 MW, less than 0.1% of the total load for the Eastern and ERCOT Interconnections.)
Howard Gugel, NERC director of performance analysis, said the industry performed well “under extremely challenging circumstances. Industry owners and operators used all the resources at their disposal to keep the grid reliable.”
Grid operators relied on voltage reductions and demand side management to prevent load sheds. NERC said the performance validated its regular training and drills “as the operators and other [… entities were able to effectively and successfully implement emergency procedures.”
Record Cold
Forty-nine cities set new record lows, with Minneapolis shivering through 62 consecutive hours of temperatures below zero from Jan. 5 to Jan. 7. On Jan. 6, the average daily temperature in the U.S. was 17.9 F, the first time the average dropped below 18 F since 1997. The 17-year run of temperatures above 18 was the longest such span on record and occurred during a period in which an increasing portion of the generating fleet had become fueled by natural gas, NERC noted.
The cold pushed many generators beyond the temperature range for which they were designed.
Nevertheless, an analysis of NERC’s Generating Availability Data System (GADS) found that most generators units performed within the equivalent forced outage rate (EFOR) range expected based on the past five years. The exception was natural gas units, which had a higher-than-expected forced outage rate in January in two regions, the Midwest Reliability Organization and Southeast Reliability Corp.
Demand Records
Eight of 10 areas included in the study — all but ISO-NE and the Florida Reliability Coordinating Council (FRCC) — set all-time winter demand records on Jan. 6 or 7. The VACAR South reliability coordinator, which includes SCE&G, busted its record by almost 18%. (NERC’s review did not include the Western Electric Coordinating Council, which was largely unaffected by the polar vortex.)
Causes
Like PJM, other regions experienced fuel deliverability problems, natural gas pipeline outages and frozen equipment. The report catalogues dozens of cold-weather problems that led to outages, delayed starts or deratings, most of them involving the freezing of water and the gelling of oil and diesel fuel.
NERC’s report makes a number of recommendations but does not call for changes to existing mandatory reliability standards. Many of the recommendations are already being taken in PJM and other regions.
Among the recommendations:
Generators
Review and update power plant weatherization programs, including procedures and staff training.
Continue or consider implementing a program for winter preparation site reviews at generation facilities.
Review the basis for reporting forced and planned outages to ensure appropriate data for unit outages and de-ratings. The review found that planned and forced generation outages in some regions exceeded worst-case scenarios used in seasonal assessments.
Consider where appropriate the temperature design basis for their plants to determine if improvements are needed for the plants to withstand lower winter temperatures without compromising their ability to withstand summer temperatures.
Review internal processes to ensure their ability to secure necessary waivers of winter environmental and/or fuel restrictions.
Oil & Natural Gas
Review natural gas supply and transportation issues, and work with gas suppliers, markets and regulators to develop appropriate actions.
Include in winter assessments reasonable losses of gas-fired generation and considerations of oil burn rates relative to oil replenishment rates to determine fuel needs for continuous operation.
Continue to improve operational awareness of the fuel status and pipeline system conditions for all generators.
Ensure that on-site fuel and fuel ordered for winter is adequately protected from gelling.
NERC will conduct a webinar Thursday to provide a preview of its 2014-15 winter outlook and to discuss cold weather events including the polar vortex and the 2011 Southwest winter outage.
PJM officials said Wednesday they are amending their proposed capacity overhaul in response to dozens of mostly critical stakeholder comments.
“Already, based on the comments, we are making adaptations to our proposal. It’s extremely helpful to get your feedback,” Executive Vice President for Markets Andy Ott said at the beginning of the three-and-a-half-hour question-and-answer session on the proposal.
“We said all along it was a proposal,” Ott said later in the session. “I can’t say it enough. You’re not talking to a wall here. This isn’t a traditional stakeholder process but it is still a stakeholder process.”
On Monday, PJM released more than 300 pages of comments from more than 50 stakeholders. While the comments reflected the traditional load vs. supply divide, there was near universal unease with how quickly PJM is attempting to introduce a new Capacity Performance product and rewrite compensation and penalty policies. (See Something for Everyone to Dislike in Capacity Performance Proposal.)
Although Wednesday’s discussion was the last scheduled stakeholder meeting before PJM issues its final proposal Oct. 7, officials said they would consider one or two additional meetings.
The Board of Managers will make the ultimate decision on what PJM files with the Federal Energy Regulatory Commission following an Enhanced Liaison Committee meeting with members Nov. 4 in Philadelphia. Although the meeting will be limited to PJM members, representatives of state regulatory commissions will also have a chance to address the board before or after the meeting, officials said.
Ott said officials are targeting a FERC filing by Dec. 1 in order to have the changes in place for the May 2015 Base Residual Auction.
Ott said the board will likely make additional changes in the plan before filing with FERC. “I think there’s a very small chance that [the Oct. 7] proposal will be filed” at FERC, Ott said.
Below are some of the issues that generated discussion Wednesday.
Force Majeure
Mike Borgatti of Gabel Associates said PJM’s proposal for “the outright elimination of force majeure is untenable.”
Borgatti said the rules would allow a coal-fired plant to escape penalties if it were unable to operate because a sinkhole swallowed a nearby substation but not if the hole made the road to the plant impassible for coal deliveries. Another stakeholder observed force majeure would not apply for a gas-fired generator that lost its pipeline to the sinkhole.
Independent Market Monitor Joe Bowring, who opposes PJM’s proposal to add an additional class of capacity, said he supports the tightened force majeure rules. “The market doesn’t care why you’re out [of service]. If you’re not producing energy, you’re not producing energy. That’s all the market cares about. It’s impossible [for the Monitor and PJM] to manage a long list of excuses.”
Ed Tatum of Old Dominion Electric Cooperative said Bowring’s analysis was an inaccurate description of the Reliability Pricing Model. “This is a resource adequacy concept. It’s not a market. … Taking an academic view of what is not a market is not going to get us” improved performance.
Officer Certification
Generators are also balking over requirements that officers certify their plants’ ability to meet the Capacity Performance requirements. Borgatti said it could be impossible to certify that a generator holds a firm gas contract three years into the future.
Another member said the requirement introduced both organizational risk and personal risk to the officer. “You’re asking the officer to certify to an unknown risk that won’t be known until after the fact,” he said. He said PJM should eliminate the requirement or add a “safe harbor” provision.
The IMM says performance incentives will be sufficient to ensure reliability and that officer certifications are unnecessary.
Ott said PJM is aware of the risk of unintended consequences from the requirement. “We certainly heard that” from the comments, he said.
Capacity Performance Requirements
Others said PJM should relax its requirement that Capacity Performance resources be able to run at full output for 16 hours for three consecutive days during weather emergencies, saying it unnecessarily excludes demand response, energy efficiency and storage.
Wil Burns, an attorney representing public interest groups said PJM should broaden its Capacity Performance definition to include resources such as DR, EE and renewables that have no fuel risk and “that can be and have been there when needed.”
PJM’s Adam Keech said the requirement was intended to cover the daily summer peak or the two daily winter peaks. But he suggested PJM might relax the requirement saying, “I don’t want to say anything is etched in stone.”
“You’re getting a sense from us that the last thing we want to do is to discourage resources that can be there,” Ott said. But he said the RTO felt that it needed operational requirements and not “just rely on the economic pressure of a performance penalty. Striking that balance will be very key.”
Despite the appellate court ruling voiding FERC’s authority over DR, “PJM believes there’s a continuing role for demand response in the wholesale market,” Mike Kormos, executive vice president for markets, assured stakeholders. “It may be there in a different format.”
Kormos said PJM would integrate its plans for DR with the capacity market “once it’s clear how FERC wants us to move forward.”
Base Capacity Assumptions
Several speakers challenged PJM’s assumption that no base capacity will be available during the peak winter week. Tatum noted that the RTO uses a probabilistic approach to account for forced outages in its calculation of loss-of-load-expectation (LOLE) and installed reserve margins (IRM).
“Zero seems pretty on-off – kind of a low number to me,” Tatum said. “I think it would be good to have a consistent approach.”
Kormos said that to count on any base capacity during the winter peak “might be overoptimistic.”
“If you look at the number of gas units that never get gas on peak [winter] days,” when generation has to compete against gas demand for heating, “it’s not as draconian as it sounds,” Kormos said.
PJM has proposed that all but 15% of peak winter load be served by the new product. “I don’t think our thinking has changed a lot on that,” agreed PJM’s Tom Falin.
Market Power
Load representatives asked PJM and the Monitor to address market power concerns, saying the new product could be subject to withholding.
Susan Bruce, representing the PJM Industrial Customer Coalition, said “strong market power protection” would be essential to winning her group’s support.
Ott endorsed the Market Monitor’s suggestion of a must-offer requirement that allows generators to submit “coupled” offers with one price for Base Capacity and a higher price for Capacity Performance.
Bowring said the best way to reduce withholding risk is to use a single annual capacity product without the new product. (Bowring also has called for eliminating Limited and Extended Summer DR). Given the higher requirements and penalties on CP, Bowring said, there will be a “very substantial incentive” for generators to withhold.
But Bowring said his staff could review proposed costs for winterization or firm fuel within coupled offers the same way it currently screens offers under the avoidable cost rate (ACR) and avoidable project investment recovery rate (APIR).
“It’s very doable. I don’t want to understate the complexity of it. It’s going to be much more complicated than it is now.”
Cost Recovery
One generator representative said his company is concerned with being able to recover the additional costs to allow its plants to meet the CP standards. “Just because you put those costs in has no bearing on whether you’ll actually see recovery for more than one year,” he said.
Bowring acknowledged capacity revenues have “not been adequately compensatory.”
Ken Carretta of Public Service Enterprise Group said generators would face additional maintenance costs as well as capital expenditures – a disconnect with the current backward-looking ACR mechanism.
“We have to figure out a way to reflect that,” Bowring agreed.
The Government Accountability Office expects 13% of the nation’s coal-fired generating capacity to retire between 2012 and 2025, an increase from the 2% to 12% range the GAO predicted two years ago.
At the same time, the GAO is reducing its forecasts for coal capacity receiving retrofits to meet Environmental Protection Agency emission regulations to 70 GW, down from its previous forecast of 102 GW.
About 38% of the total 42.2 GW expected to retire are in four PJM states: Ohio (14%), Pennsylvania (11%), Kentucky (7%) and West Virginia (6%), according to the GAO report released last week.
In a 2012 report, the GAO called for the EPA, the Department of Energy and the Federal Energy Regulatory Commission to develop a formal, joint process for monitoring the electric industry’s response to EPA regulations.
The new report said the agencies have taken steps to implement the recommendation, including regular joint meetings with RTO officials and other stakeholders.
The new report, requested by Alaska Sen. Lisa Murkowski, the ranking Republican on the Senate Energy and Natural Resources Committee, makes no additional recommendations.
Senate Confirms 2 for US NRC Posts
Stephen Burns
The Senate last week confirmed two nominees to the Nuclear Regulatory Commission, bringing the commission to full strength. Jeffrey Baran, aide to Rep. Henry Waxman (D-Calif.), and Stephen Burns, a former NRC general counsel, were confirmed with votes that generally fell along party lines.
Baran replaces Bill Magwood, who has accepted a position with the Paris-based Nuclear Energy Agency. He will finish Magwood’s term, which expires June 30, 2015. Burns will replace George Apostolakis, who left June 30 after the White House did not re-nominate him. Burns’ term will run through June 30, 2019.
EPA to Accept Comments on Carbon Rule Until Dec. 1
The Environmental Protection Agency has extended the comment period on its proposed carbon emission rule for 45 days to Dec. 1.
“We’ve got a number of requests from a variety of stakeholders that they would like more time,” Janet McCabe, acting assistant administrator for the Office of Air and Radiation, said in a press conference Tuesday.
The rule, which would affect existing power plants, is intended to cut carbon emissions from the power sector 30% below 2005 levels when it is fully implemented in 2030. The agency has received about 750,000 comments so far. McCabe said the expanded comment period would not affect plans to finalize the rule by June 1, 2015.
The Obama Administration last week threatened to veto a package of Republican-sponsored House bills that include expanding offshore drilling, approval of the Keystone XL pipeline and expedited approval of liquefied natural gas exports.
Republicans passed the proposals in a move to emphasize their stance against President Obama’s energy policies. But the White House said the bills “would roll back policies that support the continued growth of safe and responsible energy production in the United States” and run contrary “to the administration’s commitment to promoting safe and responsible domestic oil and gas development.”
Consumers Energy Reaches Accord with EPA and Justice Department
Michigan’s Consumers Energy will spend more than $2 billion on emissions-control upgrades at Michigan power plants as part of an agreement with the Environmental Protection Agency and the Department of Justice. The settlement comes at the end of five years of negotiations between the parties.
The EPA in 2007 and 2008 alleged that the company violated opacity regulations and operated some plants without necessary permits or that required emissions-control equipment. The company also agreed to pay a $2.75 million civil penalty.
The company also agreed to retire seven of its oldest coal-fired power plants: three units at the J.R. Whiting Generating Complex near Luna Pier; two at the B.C. Cobb Generating Plant in Muskegon; and two at the Karn/Weadock Generating Complex near Bay City, with a combined capacity of 950 MW.
The Nuclear Regulatory Commission has approved GE-Hitachi Nuclear Energy’s Economic Simplified Boiling Water Reactor design for a proposed third unit at Dominion Virginia Power’s North Anna nuclear power station. The NRC approval means that the reactor design meets safety requirements for use in the U.S.
The NRC’s OK was part of the design approval and construction permitting process for the Virginia utility. Dominion says it expects to receive necessary approvals in 2016 for North Anna 3, although it has not yet decided whether to build the unit.
The NRC’s approval brought some criticism. “No reactor is earthquake-proof, and Dominion has no business building another reactor on an active fault line,” said Glen Besa, director of the Sierra Club’s Virginia chapter. North Anna’s two 980-MW reactors were out of service for three months after a 5.8-magnitude earthquake in 2011. A comprehensive inspection concluded the plant suffered no damage.
Natural gas production in the U.S., bolstered by shale-gas drilling, continues to increase steadily. A report by Bentek Energy estimated that production increased 0.4 billion cubic feet per day from July to August. Bentek says production set a record of 69.04 billion cubic feet per day on Aug. 29, eclipsing a record set the previous month.
“The U.S. continues to break natural gas production records almost on a daily basis,” said Jack Weixel, Bentek’s director of energy analysis. August was the eighth consecutive month of production increases. Compared to August last year, natural gas production was up 6%.
Sherwood-Randall Confirmed as DOE Deputy Secretary
The Senate confirmed the appointment of Elizabeth Sherwood-Randall to the No. 2 post at the Department of Energy last week.
Sherwood-Randall was President Obama’s adviser on nuclear weapons and arms control since 2013. Before that, she was his European affairs adviser. She will replace Daniel Poneman, who stepped down as deputy secretary in June after five years.
“Liz’s confirmation comes at a historic time in our nation’s energy evolution,” Energy Secretary Ernest Moniz said. “She joins us with deep expertise in the department’s nuclear security mission, including both nuclear weapons and countering proliferation.”
A Department of Energy report that tested water wells near a natural gas drilling site that was hydraulically fractured found no evidence that fracking had contaminated groundwater. The study, released last week, found that no chemicals used in the fracking process had migrated to six test water wells at a Pennsylvania site.
Critics said the study was too small to prove that fracking is safe. They called for tighter regulation of drilling until a final determination is made.
PJM will revise its eMKT application to capture more detailed information and require generation owners to use it to verify their operating parameters under a proposal outlined to members last week.
Generation owners will be required to ensure all data in eMKT is accurate, particularly notification times, minimum run times, unit status and unit limits (emergency and economic min & max).
PJM will also require owners to make all updates in eMKT, and operators will use only that data for unit commitment decisions. Verbal notifications will be permitted only if previous unit commitments cannot be met or a unit trips or encounters other problems in real time.
“We want to get away from all the phone calls and changing information in real time,” said PJM’s Chantal Hendrzak, who presented the proposal to the Markets and Reliability Committee Thursday. “We want to be able to pull that information out of eMKT.”
Among the additional information that PJM will be requiring are details on units’ dual-fuel capabilities (e.g., time to transition, megawatt output during transition) and operational restrictions (e.g., emissions limits).
Generators would also be able to update their energy offers and cost-based start-up and no-load costs during the operating day to reflect gas-price volatility.
The proposed changes are expected to be brought to an Operating Committee vote next month.
PPL’s plan to spin off its generation needs additional mitigation to address local market power concerns, PJM’s Independent Market Monitor told the Federal Energy Regulatory Commission last week.
PPL and Riverstone Holdings announced in June they would join their generation businesses into a publicly traded independent power producer named Talen Energy. The new company would own 15,320 MW of capacity, including 12,000 MW in PJM.
In their application to FERC (EC14-112), the companies proposed selling about 1,300 MW of PJM generation to avoid market power complaints. The companies said that no company with more than 10% of PJM’s summer installed capacity would be permitted to bid for the plants. That would leave out Public Service Enterprise Group, Exelon and NRG Energy. (See PPL, Riverstone ID Plants for Sale in Talen Spinoff.)
Not Enough
The Market Monitor told FERC that isn’t enough.
“The transaction, even with the applicants’ proposed mitigation, would have an anticompetitive impact,” the Monitor’s analysis says.
“The analysis concludes that the transaction would significantly increase concentration in specific, highly concentrated locational energy markets, would increase concentration in the capacity market and would have minimal effect on the market for regulation.”
The Monitor said “behavioral mitigation” would level the playing field.
It recommended that FERC:
Require Talen to make cost-based offers in the energy and regulation market.
Require Talen to offer the same plants and output as PPL did, prohibiting it from holding back generation to drive prices up.
Expand the list of companies barred from purchasing the plants sold in mitigation to include American Electric Power, FirstEnergy, Dominion Resources, Duke Energy and Calpine. (Editor’s Note: The IMM said its initial filing, which was referenced in an earlier version of this story, erroneously included Edison International and failed to include Duke).
PPL questioned the IMM analysis and said it remains confident of FERC approval.
“PPL believes that the mitigation proposal addresses completely any potential FERC issues with concentration of power generation assets within PJM,” spokesman George Lewis said. “On first read, PPL believes the IMM’s comments are not justified by the facts of the PPL-Riverstone combination. We will review the comments in greater detail and respond at FERC.”
Allegheny Protest
The Monitor was not the only party to challenge the PPL-Riverstone deal. Allegheny Electric Cooperative, which owns 10% of the Susquehanna nuclear plant that is part of the spinoff, told FERC that it was blindsided by the deal and has not received assurances that the new owners are qualified to run a nuclear plant.
Allegheny said it first heard of the Talen deal late on the night of June 9, when PPL and Riverstone announced it.
“Even though Allegheny is a co-owner of and co-licensee for Susquehanna, PPL did not advise or provide any information to Allegheny concerning the proposed transaction until the proposed transaction was publicly announced,” the company wrote in its protest to FERC.
“The filing does not explain how PPL is complying with its contractual obligations to Allegheny regarding the operation and maintenance of Susquehanna in transferring its interests in the facility to Talen Energy,” Allegheny wrote in its protest. “Further, it fails to describe Talen Energy’s competence in owning, operating, maintaining and providing for the overall management of a facility as important to the region — both in terms of power supply and reliability — as Susquehanna.”
Lewis wouldn’t directly address the Allegheny complaints. “We are reviewing those as well and will provide a response at FERC,” he said.
In a July filing asking the Nuclear Regulatory Commission to approve the transfer of Susquehanna’s license, PPL said the spinoff will have little impact on plant operations. “The proposed transaction will not result in any undue risk to public health and safety and will not be inimical to the common defense and security,” PPL wrote.
Two of the finalists for the Artificial Island transmission fix have offered to cap their costs while a third has teamed up with Pepco Holdings Inc. in a bid to improve its chances.
In July, PJM’s Board of Managers delayed action on planners’ recommendation that it select Public Service Electric & Gas to address stability problems at Artificial Island at a cost of $211-$257 million. The board told PSE&G and finalists Transource Energy and Dominion Resources to “supplement” their proposals in response to finalist LS Power’s offer to cap its project cost at $171 million. (See PJM Board Puts the Brakes on Artificial Island Selection.)
In response, PSE&G offered to cap its price at $221 million and LS Power reduced its cap to $146 million.
Dominion declined to provide a cost cap but revised its estimate for one proposal to $174 million, including a 10% contingency for construction and a 50% contingency for real estate and permitting.
Transource, which also declined to agree to a cost cap, revised its estimated cost to $203 million, excluding work required at the Salem station and a $52.3 million contingency. The company, which had previously estimated its project at $165 million to $208 million, said its revised estimate reflected the need to employ specialized drilling techniques and the addition of a second underwater cable.
Transource said it would forego 50% of any return-on-equity incentives on any costs between $203 million and $255.3 million and 100% of the ROE incentives on any costs exceeding $255.3 million.
Transource also disclosed that it had signed a memorandum of understanding with Pepco, parent of Delmarva Power & Light, to partner on the project. “This arrangement significantly improves the likelihood of project success based on PHI/Delmarva’s significant experience working in the project area, familiarity working with the numerous permitting agencies and on‐the‐ground resources to provide operations and maintenance services over the life of the project,” Transource said.
FERC Oversight
The board delayed action on staff’s recommendation of PSE&G following criticism over planners’ decision to eliminate two 500-kV lines from the company’s original $1.066 billion proposal.
Seeking to avoid additional controversy, the board also asked the Federal Energy Regulatory Commission to appoint an administrative law judge to serve “in a non-decisional role to ensure the fairness and due process” regarding PJM’s discussions with the finalists.
ALJ Steven Sterner will attend meetings between PJM and the finalists or review agendas and proposed questions to “ensure that PJM’s line of inquiry is consistent with each of the bidders and that no bidder is given an undue advantage in their presentation to PJM,” the RTO said in an Aug. 29 letter to Chief ALJ Curtis Wagner.
Sterner “will observe and comment upon … the fairness of the process undertaken by PJM through these final negotiations but not attempt to influence PJM staff’s substantive recommendation or the final PJM board decision in any way.”
PJM will not be required to follow the judge’s recommendations.
The Federal Energy Regulatory Commission and New York regulators will hold a joint technical conference Nov. 5 to discuss the state’s capacity market and plans to revamp the utility business model to accommodate renewable energy and distributed resources.
FERC’s conference with the New York Public Service Commission will be held from 9:30 a.m. to 5 p.m. at the New York Institute of Technology in Manhattan.
Reforming the Energy Vision
One focus of the conference will be the PSC’s Reforming the Energy Vision (REV) initiative, which the commission announced in April.
The PSC noted that technological innovation and the increased competitiveness of renewable energy and distributed resources is occurring as the state confronts aging infrastructure, extreme weather events and challenges to system security.
FERC Chairman Cheryl LaFleur said the commission wants to learn about how the REV program intends to reform the state’s energy industry and regulatory practices to meet these challenges.
“The New York PSC and New York leadership have produced some interesting things around their REV … that would potentially require evolution in the role in some of the things that we’re looking for from the ISO,” she explained after announcing the technical conference at last week’s FERC meeting.
The PSC released a straw proposal in August that found “There is large potential for the integration of Distributed Energy Resources (DERs) into the New York electricity market, via a Distributed System Platform (DSP) framework.”
The report outlined potential reforms in the utility ratemaking process “to provide the correct incentives for utilities and markets to develop a cleaner and more efficient electric system.”
A two-track public proceeding is examining the regulatory reforms. The first track examines the role of distribution utilities in deploying distributed energy resources to promote load management and system efficiency, including peak load reductions. The second, parallel track will consider changes in tariff and market designs and incentives to align utility interests with the policy objectives.
Public comment on the proposal was due yesterday.
Capacity Zone Controversy
The Nov. 5 conference will also be something of a fence-mending effort for FERC, following its approval of a controversial capacity zone intended to address transmission congestion north of New York City.
Opponents claim the zone, which took effect May 1, will create a windfall for existing generation owners before the region’s constrained supply issues can be full addressed.
In July, New York Sens. Charles Schumer and Kirsten Gillibrand voted against the reconfirmation of LaFleur, a fellow Democrat, to FERC. Before the vote, Majority Leader Harry Reid (D-Nev.) said he had spoken to LaFleur about the criticism of the capacity zone and that she had agreed to “take a hard look at” it. (See New Yorkers Upset over NYISO Capacity Zone.)
LaFleur Thursday acknowledged the controversy over FERC’s approval of the zone. “Those orders are final but it seemed like it might be a good time to consider: Is the capacity market attracting the investment we need for reliability? Let’s have a refresher on where we are,” she said.
