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August 13, 2024

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FERC Punts SMECO-J.P. Morgan Capacity Dispute to Courts

By Suzanne Herel

FERC last week dismissed a complaint by Southern Maryland Electric Cooperative alleging that it has the right to a Capacity Performance credit from J.P. Morgan Ventures Energy Corp., saying the contractual dispute would be better resolved by a court (EL16-35).

In 2011, the parties executed a capacity purchase and day-ahead heat rate call option on physical electricity for the Brandywine Generation Facility from Jan. 1, 2014, through Dec. 31, 2021. The power purchase agreement provides SMECO a 225-MW Reliability Pricing Model capacity credit in exchange for a monthly payment to JPMVEC.

SMECO said that it did not believe JPMVEC intended to transfer the credit under PJM’s new Capacity Performance model and instead treat the product as base capacity.

“Determination of the dispute between SMECO and JPMVEC depends upon whether the parties contracted to sell and purchase capacity specifically from the Brandywine facility with the intent to allow SMECO to meet its RPM obligation, as SMECO claims, or whether the parties contracted for the transfer of any type of capacity from any source without regard to SMECO’s RPM obligation, as JPMVEC argues,” the commission ruled in declining to exercise primary jurisdiction in the case. “The outcome of this matter appears to turn on interpretation of the parties’ intentions and construction of the relevant clauses in the Brandywine PPA rather than any determination requiring our special expertise.”

Commissioner Cheryl LaFleur dissented from the opinion, saying the decision “effectively consigns SMECO to a potentially lengthy and costly court proceeding to resolve what is, in my view, a clear and easily resolved contractual interpretation that is squarely within the commission’s jurisdiction and expertise.”

Not only would she have supported exercising primary jurisdiction in the matter, she said, she would “find that the parties’ contract requires JPMVEC to provide SMECO with capacity credits to meet SMECO’s obligations under the RPM.”

In addition, LaFleur said, FERC erred by “failing to frame the dispute between these two parties in the proper context of the broader transition underway in the PJM capacity market.”

She urged the commission to exercise primary jurisdiction over future Capacity Performance issues to ensure consistent interpretation of common contractual language and avoid the unintended undermining of Capacity Performance reforms.

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FERC Approves ISO-NE FCA 1 Refund Plan

By Michael Brooks

ISO-NE will issue more than $20 million in refunds to capacity resources that were prevented from reducing their offers in Connecticut for reliability reasons in the 2008 Forward Capacity Auction under an order issued by FERC last week (ER08-633).

Refund Distribution Table (ISO NE)
Load-serving entities that will have to make additional capacity payments under ISO-NE’s resettlement plan.

Under the RTO’s “proration” rule at the time, the total payment to all listed capacity resources had to equal the clearing price multiplied by the installed capacity requirement. To achieve this, resources could either receive capacity payments lower than the clearing price (price proration) or reduce their capacity supply (quantity proration). All proration, however, was subject to a reliability review.

Public Service Enterprise Group complained that ISO-NE barred it from prorating its capacity supply in Connecticut, forcing the company to offer at a lower price, which the company said cost it $2.8 million. When its protest and rehearing request were denied by FERC, the company sued in federal court. The D.C. Circuit Court of Appeals ruled in favor of PSEG and remanded the case back to the commission.

Last year, FERC reversed its decision, saying, “We now find that where resources needed for reliability were prohibited from prorating quantity under the proration rule, they should have received the full market clearing price for each megawatt offered.” It ordered ISO-NE to provide a plan for resettlement.

The RTO reported that 5,870 MW would have been prorated had plants been allowed to. The clearing price for FCA 1, conducted in February 2008, was $4.50/kW-month. To determine how much each plant would be owed, ISO-NE took the difference between the clearing price and the prorated price, $4.254/kW-month, converted it to megawatt-years and multiplied it by 5,870. The result was about $17.3 million in refunds, plus about $3.1 million in interest. The RTO said it would recalculate the interest owed upon FERC’s order, so the final amount refunded to companies will be higher.

“We find the resettlements … appropriate to ensure that PSEG and other Connecticut resources that were not able to prorate quantity be paid the full capacity clearing price for each of the megawatts that cleared FCA 1,” the commission said.

Eversource Energy, which was Northeast Utilities at the time of the auction, will pay the bulk of the refunds, at almost $15.6 million. UIL Holdings, now part of Avangrid, will pay about $3.8 million.

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Generators Rebut PJM Study on Investment in Competitive Markets

By Suzanne Herel

A coalition of generators led by American Electric Power and FirstEnergy last week responded to PJM’s analysis of resource investment in competitive markets, saying it presents a skewed view of the risks and benefits of such constructs compared with the traditional regulated model.

Kyger Creek Power Plant - Generators PJM competitive markets
Kyger Creek Power Plant

Joining AEP and FirstEnergy in a May 19 letter to the Board of Managers were Dayton Power and Light, Duke Energy Ohio and Kentucky, Buckeye Power and East Kentucky Power Cooperative.

The PJM study concluded that the RTO’s markets more efficiently attract cost-effective new generation and minimize risk to consumers. (See PJM Study Defends Markets, Warns State Policies can Harm Competition.)

The study was commissioned by the board after AEP and FirstEnergy asked Ohio regulators, and Exelon asked Illinois legislators, for financial aid to support money-losing generators.

The generators said PJM’s paper fails to point out that competitive markets have achieved their benefits because of legacy generation and transmission assets that were built under the regulated utility model, noting that PJM had a reserve margin of more than 20% when it began the capacity market in 2007.

“The paper presents a case in which nuclear and coal baseload resources that do not clear the capacity market for a given delivery year should not have been built. It is naive to think that a future driven by marginal resources through short-term capacity markets can adequately serve customers,” the letter said.

“The [Reliability Pricing Model] construct has never provided long-term price support for investments in long-life assets,” it said. “As a result, a significant amount of generation [in western PJM] has, or is seeking, some type of retail rate support.” (See PUCO Grants FirstEnergy Rehearing on PPA; Opponents File Protests and Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes.)

The signatories represent 44,000 MW of capacity in the RTO and serve more than 11 million consumers with about 69,000 MW of load. They note that 30% of the capacity in PJM comes from suppliers who operate under a traditional regulatory model.

“We strongly urge the PJM board to recognize that there is a place within PJM for generation supported by the market and by traditional cost-of-service regulation,” the letter said.

The companies said there were several major weaknesses in the PJM report:

  • Risks to the consumer. PJM’s contention that customers face less risk in a deregulated model is “a short-term view,” the letter said, and is greatly influenced by recent decreases in the price of gas. “In contrast, the regulated paradigm inherently takes a long-term view of investments necessary to maintain proper fuel diversity, plant type diversity, transmission needs and reliability, which results in reduced market volatility and consumer benefits.”
  • Value proposition of an integrated utility model. Regulated utilities have a legal long-term commitment to serve customers, the letter said, whereas merchant generation can close up shop if they don’t receive the desired return. “PJM does not account for any necessary transmission investment associated with premature retirement of baseload generation,” it said. “Integrated resource plans holistically consider these costs as well as societal and policy objectives. … Customers pay for the cost of new transmission, which often can exceed the costs of keeping a unit online.”
  • Innovation. “PJM’s market rules and its stakeholder process result in a sluggish response to change,” the letter said, citing what it called “the inability of the markets to accommodate variables such as changing fuel mixes and resource adequacy as a result of environmental policies.”
  • New investment. The writers contend that market signals have not attracted new technology, and that renewable generation largely relies on bilateral arrangements or government subsidies. They say the capacity market’s one-year clearing price, three years in advance, results in increased price volatility and higher consumer costs.
  • Fuel diversity. “PJM’s position that legislators and policymakers should solve the issue of diversity contradicts PJM’s overall premise that any market outcome is superior to regulation,” the letter said.

In closing, the writers note that PJM said its paper was “intended as the beginning of a dialogue on resource investment.”

“We are ready to engage in a fact-based discussion of the risks and benefits associated with different market and regulatory paradigms,” they said, urging PJM to “focus on a market design that accounts for transmission costs, ensures both robust competition and adequate compensation for diverse capacity resources and respects the roles and responsibilities of the states in providing a comprehensive approach to least-cost reliability for consumers.”

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Former PUCO Chairman Andre Porter Joins MISO

By Amanda Durish Cook

Former Public Utilities Commission of Ohio Chairman Andre Porter is crossing state lines to become MISO’s general counsel.

Andre Porter, PUCO, MISO
Porter

He will replace Stephen Kozey, who will continue in his other roles overseeing compliance services and serving as secretary to the board. Kozey, the RTO’s first general counsel, will be able to devote more time to remaining responsibilities and advise Porter as he takes on the role, according to MISO.

Porter will begin work at MISO’s Carmel, Ind., headquarters on June 27.

Porter said he did not seek nor consider positions with other RTOs. “MISO is the only place for me. It’s the opportunity of a lifetime … and an exciting one.”

MISO spokesperson Andy Schonert said bringing Porter into MISO involved an “ongoing conversation” between Porter and the RTO, while Porter said he was able to develop a longstanding relationship with MISO from his work in PJM. “I’ve always followed MISO and admired MISO’s transparency. I’m hopeful that I can add to what is already a spectacular team,” he said.

MISO CEO John Bear said Porter’s expertise is “a great match” for the RTO.

“Andre’s background spans a broad spectrum of the energy industry, and he has extensive experience working with commissions and FERC,” Bear said.

Porter holds a bachelor’s degree in political science from Capital University and a law degree from The Ohio State University Moritz College of Law.

Porter worked as an energy, public utilities and real estate taxation attorney before serving as a PUCO commissioner from 2011–2013.

Before returning to PUCO as chairman, Porter led the Ohio Department of Commerce.

Porter resigned from PUCO late last month, just over a year after taking the position and less than a month after PUCO unanimously approved controversial, eight-year power purchase agreements for FirstEnergy and American Electric Power. Porter’s term wasn’t slated to expire until April 2020. (See PUCO’s Porter Submits Resignation.)

The PPAs guarantee the utilities’ merchant generators receive revenue streams above current market prices to shield them from cheaper natural gas generation. The companies asked PUCO to cancel the agreements after FERC ruled that they would need to be reviewed under the commission’s affiliate abuse test. (See PUCO Grants FirstEnergy Rehearing on PPA; Opponents File Protests.) FERC said last month that in spite of Ohio’s retail choice law, the companies’ ratepayers were effectively “captive” customers because the PPAs impose non-bypassable distribution charges.

Critics contend the PPAs, which weren’t subject to competition, could impose billions in extra costs on consumers and equate to coal bailouts. FirstEnergy and AEP maintain the PPAs are essential in keeping their struggling Ohio coal plants operational, and AEP CEO Nick Akins said the company intends to lobby Ohio legislators to reregulate the deregulated Ohio power market or sell all its generation in the state before it consents to submitting its PPA for FERC review.

Porter declined to say whether he was brought back to PUCO to complete the AEP/FirstEnergy agreements.

“I came back to the commission because there were challenges, and I’m the kind of guy that seeks out challenges. It was just really about coming back to a place where I could help. I certainly appreciated my time working with the utilities of Ohio.”

Porter also declined to answer questions on what he thought of the status of the deals now and if AEP could run a successful bid for reregulation in Ohio, citing FERC’s ongoing review and his new commitment to MISO.

“Right now I’m squarely focused on MISO,” Porter said.

Gov. John Kasich named PUCO Vice Chair Asim Haque to replace Porter, making Haque the fourth PUCO chairman in four years.

“I enjoyed my time at PUCO, and I’m forever grateful to Gov. Kasich for the opportunity. I think my successor, Mr. Haque, is more than capable; he’s going to lead with clarity, and the state of Ohio will be well served,” Porter said.

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Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid

By Tom Kleckner

The Public Utility Commission of Texas on Thursday rejected all motions for rehearing in Hunt Consolidated’s proposed acquisition of Oncor, effectively closing the books on a deal thought to be key to Energy Future Holdings’ emergence from bankruptcy (Docket No. 45188).

The commission’s unanimous vote allowed its March 24 order conditionally approving the acquisition to stand. Because the Hunt group has said it couldn’t complete the deal as approved, that means the order will “evaporate,” as Commissioner Ken Anderson put it.

The Hunt group and other EFH creditors had filed a request May 18 asking the commission to vacate the order and dismiss the proceeding, which would have left open the possibility of a new application.

Commission Chair Donna Nelson said she was joining her two fellow commissioners in denying the motions “solely in the interest of allowing us to be done with this today.”

“Time is of the essence in this case,” she said, “which is funny because of how it’s dragged along.”

Oncor, Texas PUC, Hunt Consolidated

The Hunt group asked the commission in September for approval to acquire Oncor, the largest transmission company in Texas, for almost $20 billion. In March, the commission approved Hunt’s proposal to split Oncor into two companies, one of which would operate as a real estate investment trust (REIT). (See Texas Commission Approves Oncor REIT Structure.)

However, the PUC attached conditions to the approval that included sharing the REIT’s tax savings with Oncor customers, which EFH creditors found unacceptable. EFH filed a new Chapter 11 reorganization plan May 1, saying it would be unable to complete the Oncor acquisition as it tries to eliminate $42 billion in debt. (See EFH Files New Chapter 11 Plan; Oncor-Hunt Deal in Doubt.)

Richard Nolan, an attorney for the Hunt group, said his parties had concluded May 17 that if they were to pursue a new transaction, “it will require a new application.”

“From our perspective … it would be more helpful to clear the decks and make a fresh start,” Nolan said. He said the original proceeding became moot when the acquisition was terminated.

He received no argument from intervenors and PUC staff, who all agreed with denying the rehearing request.

“I don’t want to go through another proceeding where we end up with major stumbling blocks,” Anderson said. “ERCOT, and the Texas power market, will benefit from getting this matter resolved.”

The Hunt group said it will continue to work with stakeholders on a plan that meets its goal of keeping Oncor under management control by Texans. “The commission’s actions today now allow all parties to engage in conversations about next steps,” Hunt spokesperson Jeanne Phillips said in a statement.

While Phillips, Anderson and others have expressed a strong desire that Oncor remain under in-state control, Florida-based NextEra Energy reportedly remains a suitor. The company made its own bid for Oncor last year, only to be outflanked by the Hunt group.

Anderson said that with the proceeding behind the commission, it can now take a more assertive role in EFH’s bankruptcy case in Delaware.

“We’ve generally been pretty passive up until now,” he said.

Under EFH’s new bankruptcy exit plan, it would again be broken up into two parts (Oncor and the competitive Luminant and TXU Energy businesses), with noteholders potentially being able to grab Oncor. EFH has asked the bankruptcy court to hold a hearing on the plan Aug. 1.

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Pipeline Protesters Force FERC to Close Monthly Meeting

By Michael Brooks

WASHINGTON — Citing safety concerns, FERC closed its monthly meeting to the public Thursday, allowing only staff, guests and credentialed members of the press inside commission headquarters.

The meeting was broadcast via the Internet, which Chairman Norman Bay said allowed the commission to meet its “statutory requirement” under the Government in the Sunshine Act to allow the public to observe the meeting.

“The decision to conduct this open meeting by webcast only was not made lightly,” Bay said. “It was made after consultation with law enforcement and our security staff, and the primary concern was preserving the safety of the public and commission staff. The webcast allows us to maintain the ability of the public to observe and listen to the commission meeting.”

Beyond Extreme Energy protesters outside FERC headquarters © RTO Insider
Beyond Extreme Energy protesters outside FERC headquarters © RTO Insider

The decision to close the meeting — possibly the first time the commission has held a webcast-only open meeting, according to Bay — came amidst a week of intense protest activity by environmentalist group Beyond Extreme Energy (BXE). Members of the group demonstrated outside the homes of Commissioner Tony Clark on Monday and Bay and Commissioner Cheryl LaFleur on Wednesday. They were also already camped outside commission headquarters prior to the start of the meeting but had departed by the time the meeting ended.

“I, too, find it unfortunate that we had to decide to restrict access to the building today,” Clark said. “But it was done with the consultation of law enforcement and I understand why. If you look at the room in the headquarters building, it’s simply not designed to handle the activities that were being discussed, and when decisions like this are made, public safety has to come first.”

Bay declined to say what activity the commission was expecting to take place. BXE’s modus operandi is to interrupt meetings with statements criticizing the commission’s approval of natural gas infrastructure before being escorted out by security. Known members have been barred from the meeting room, relegated to a side room to watch the meetings on TV. (See Meet the People Making Life a Little More Difficult for FERC this Week.)

Melinda Tuhus, a Beyond Extreme Energy spokeswoman, said that the group was not going to do anything different in the meeting room beyond their normal interruptions. She said there were about a dozen protesters, out of the 50 to 60 total, at the rally outside FERC on Thursday who had never attended an open meeting.

“The commissioners know that we’re nonviolent activists,” Tuhus said. “That’s a fundamental precept of our organization. … The commissioners know that.”

Tuhus speculated that the commissioners overreacted to the demonstrations outside their homes. “We made absolutely no threats.”

Last week, Bay had to be escorted out of the Independent Power Producers of New York’s annual spring conference when protesters rushed the stage while he was holding a question-and-answer session.

During the protest outside FERC headquarters, the Rev. Lennox Yearwood of the HipHop Caucus criticized President Obama, California Gov. Jerry Brown and Canadian Prime Minister Justin Trudeau for supporting fracking. “They are not climate leaders until they realize we must transition to 100% renewable energy,” he said.

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MISO Sees Enough Capacity for Summer

By Amanda Durish Cook

Carmel, Ind. — MISO has adequate capacity to meet summer demand, though there’s a good chance the RTO will dip into its load-modifying resources, officials said at a summer readiness workshop last week.

MISO officials reported 148.8 GW of capacity to meet a projected demand of 125.9 GW, giving it an 18.2% reserve margin, well above its 15.2% requirement. Compared with last year’s summer forecast, available capacity declined by 1.5 GW, while the load forecast decreased by 1.4 GW.

MISO Summer 2016 Risk Analysis MISO - capacity

Probabilities

MISO said there is a 72% probability it will need to deploy some of its 9.5 GW of load-modifying resources, but only a 10% chance it will use all of them and have to tap operating reserves.

There is a 4.3% probability that MISO will deplete operating reserves and be forced to order load shedding, Vice President of System Operations Todd Ramey said.

Ramey said that even when MISO declares a capacity emergency, 10,000 MW are still available for use. “Emergency doesn’t mean imminent load shed,” he said. Unit retirements that reduced capacity create “a new operating reality” for the RTO, he added.

MISO is close to completing its 2016 Coordinated Seasonal Assessment for summer, which identifies potential stressors to the transmission system. “For this summer, we didn’t see any outstanding issues,” MISO transmission planning engineer Carlos Bandak said. MISO’s full analysis is due by end of the month.

Gas Inventory High

miso capacityPhil Van Schaack, MISO electric-gas operations coordinator, said there was a record 2,480 Bcf of natural gas in storage at the beginning of April, a 60% rise over last year’s end-of-winter inventory.

Van Schaack also noted natural gas prices in the New York Mercantile Exchange hit lows in March not seen since 1999, at $1.64/MMBtu. He said the oversupplied market, coupled with forecasts of a warmer-than-normal summer, could result in “significant power burns, longer runs and higher capacity [factors for] gas units, similar to the summer of 2012.”

Emergency Offer Floors

MISO has established new emergency offer floors to combat depressed emergency prices. Michael Robinson, the RTO’s principal adviser for market design, said depressed emergency prices occur because offer prices for emergency resources either aren’t available or are cheaper than an economic resource dispatched prior to the emergency declaration.

Now, when a maximum generation emergency warning is issued, the pricing floor is set at the highest available economic offer. After a maximum generation emergency event is declared, the pricing floor moves up to the highest available economic and emergency offer.

Hurricane Readiness

MISO has assembled a hurricane readiness team to identify inadequacies in contingency plans for MISO South, which enters the Atlantic hurricane season next month.

“We hope to focus on communication coordination limitations,” project leader Van Schaack said. “We’ve had mild hurricane seasons since the integration of MISO South. We want to make sure we are educated on how to prepare.”

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Company Briefs

A 485,000-pound Exelon Generation wind turbine that toppled in February “basically shook itself apart” after a mechanism meant to control its speed failed, according to a company investigation.

exelongenerationsourceexelonAll three cylinders of the pitch system in the eight-year-old Vestas V82 1.65-MW turbine in Oliver Township, Mich., suffered oil leaks, according to an investigation by Exelon. The failed pitch system, and 45-mph winds, pushed the blades to rotate at 18 rpm, far more than the 14.4 rpm nominal speed. Nobody was injured, but the $1.5 million turbine was destroyed when it fell to the ground.

All of the other turbines of that model were inspected, and none showed problems with more than one cylinder. It is the only recorded instance of a catastrophic failure of the Danish-designed turbine, officials said.

More: Huron Daily Tribune

Will Talen Energy Be Taken Private?

talenenergysourcetalenRiverstone Holdings, Talen Energy’s largest shareholder at 35%, reportedly is leading an effort to take the independent power producer private.

Bloomberg cited anonymous sources in its report, which said Talen has not decided whether to accept that or other offers.

Talen, which spun off from PPL last June, reported a first-quarter profit of $151 million.

More: Bloomberg; The Morning Call

Duke to Build $55M 21-MW Plant at University

dukeuniversitysourcedukeDuke Energy will build a 21-MW combined heat and power plant at Duke University that will cut the university’s carbon emissions by 25%. The natural gas-fired plant will fuel a turbine that will turn a generator, and the waste heat will be captured to produce steam for buildings. The project still needs approval from the North Carolina Utilities Commission.

It will be the company’s first foray into heat plants in the Carolinas. The university will sign a 35-year operations contract with the utility.

More: Charlotte Business Journal

Talen to Pay More than $1M for 2005 Fly Ash Spill

martinscreeksourcetalenTalen Energy will pay more than $1 million to agencies in Pennsylvania, Delaware and New Jersey to settle a claim stemming from a 2005 fly ash spill at its Martins Creek Power Plant on the Delaware River.

Under the ownership of Talen’s predecessor company, PPL, a containment basin burst, spilling about 100 million gallons of fly ash and water into local fields, Oughoughton Creek and the Delaware River.

The Martins Creek coal-fired units stopped running in 2007, and the plant was converted to natural gas.

More: LehighValleyLive.com

Six Energy Companies Launch Grid Assurance Sparing Program

aepohiosourceaepSix energy companies have launched Grid Assurance, a company providing shared transmission parts inventory to restore service during emergency outages more quickly.

American Electric Power, Berkshire Hathaway Energy, Duke Energy, Edison International, Eversource Energy and Great Plains Energy worked together over a year to form the independent company this month. Kansas City Power & Light Senior Vice President Michael Deggendorf was named Grid Assurance CEO.

Grid Assurance is a subscription-based service open to transmission providers where large transformers, circuit breakers and other system components are stored in warehouses around the U.S., available for quick dispatch in case of a catastrophic event.

More: American Electric Power

ATC Restructures to Facilitate Expansion

americantransmissioncosourceatcThe Wisconsin Public Service Commission last week approved American Transmission Co.’s reorganization plan that will allow the company to more easily take on transmission work in other states.

Under the plan, the Wisconsin-based ATC will create a separate holding company specifically for out-of-state investments. The company still needs approval from the Illinois Commerce Commission, whose decision is expected later this year.

ATC spokeswoman Anne Spaltholz said the company is focusing on a string of potential Midwestern projects, in addition to possibly building a line to connect a Wyoming wind farm to California. ATC is also eyeing the formation of a separate transmission utility in Alaska.

More: Milwaukee Journal Sentinel

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More Pipelines for New England: ‘Gold-plating’ or Necessity?

By William Opalka

NORTH FALMOUTH, Mass. — It all comes back to pipelines.

Discussions about New England’s energy future invariably end up focused on the outsized role natural gas plays in the region’s power mix, and how that aligns or runs counter to various policy goals. Also debated is who should pay for pipeline build-outs.

A discussion at the 23rd Annual New England Energy Conference on Wednesday, presented by the Northeast Energy and Commerce Association and the Connecticut Power and Energy Society, was no different.

Most speakers agreed that some pipeline capacity is needed (though environmental groups, energy efficiency advocates and LNG suppliers dispute that premise).

The discussion came three weeks after the suspension of the Northeast Energy Direct pipeline and amid ongoing controversy over whether regulators should allow electric ratepayer support for the proposed Access Northeast project. (See Kinder Morgan Board Suspends Work on Northeast Energy Direct Pipeline.)

Dan Dolan - New England Energy Conference - Pipelines
Dolan © RTO Insider

Dan Dolan, president of the New England Power Generators Association, said new generation clearing in recent Forward Capacity Auctions show the market has responded to the region’s needs. Smaller gas infrastructure projects shows that contractual commitments from distribution customers are increasing supply without electric ratepayer support, he added.

“We look through any public policy proposal through the prism of subsidies. Given that rubric, no, we don’t support” Access Northeast, Dolan said. “As we see contracts, that [demonstrates what] should be built, but I don’t think we need to gold-plate the system.”

Serna © RTO Insider - New England Energy Conference - Pipelines
Serna © RTO Insider

Not so, according to Camilo Serna, vice president of strategic planning and policy for Eversource Energy, who disputed the subsidy characterization. “The alternative is that the [electric] customers will be paying more in the winter,” he said.

Eversource, which is a partner in Access Northeast, predicts consumer electricity costs will drop by $1 billion to $2 billion annually with increased natural gas supply.

“The market hasn’t been able to deliver that infrastructure. The generators don’t have the incentive to commit [to pipeline contracts]. I don’t think it’s gold-plating if you see that we really haven’t made any gas infrastructure investments for 20 years,” Serna said.

Rebecca Tepper - New England Energy Conference - Pipelines
Tepper © RTO Insider

Whether the investment falls on pipeline developers or electric ratepayers will be resolved for Massachusetts by the state’s Supreme Judicial Court. Arguments were held recently on an order by the state’s Department of Public Utilities allowing pipeline cost recovery. The order was challenged by Massachusetts Attorney General Maura Healey.

“We don’t think it’s legal. It’s not consistent with the [state] restructuring act, which was to take ratepayers out of the business of investing in large infrastructure projects and put the risk on private investors,” said Rebecca Tepper, deputy chief of the attorney general’s energy and environmental bureau.

Anne George - New England Energy Conference - Pipelines
George © RTO Insider

“We get very nervous about making big infrastructure decisions on the backs of ratepayers based on something that happened two winters ago when the circumstances today are entirely different,” she added.

Although ISO-NE is project-neutral, it says more pipeline capacity is necessary for stable and affordable electricity, as nearly half of New England’s supply comes from gas-fired generation, a share that is expected to increase.

“We still see natural gas as one of our primary challenges,” said Anne George, vice president, external affairs and communications for ISO-NE. “We see demand for it to continue to grow and we have not built any pipeline infrastructure to support that growth.”

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Omaha PPD Recommends Closing Fort Calhoun

By Tom Kleckner

Omaha Public Power District is recommending that its Fort Calhoun Nuclear Generating Station end operations by the end of 2016 and begin the decommissioning process.

Fort Calhoun Nuclear Plant (Omaha PPD) - smallest nuclear plant
Fort Calhoun Nuclear Generating Station Omaha PPD

CEO Tim Burke told OPPD’s Board of Directors on May 12 that an economic analysis concluded that Fort Calhoun “is not financially sustainable.”

“The analysis considered market conditions, economies of scale and the proposed Clean Power Plan,” Burke said in a statement.

The board is expected to vote on the recommendation at its June 16 meeting.

At 478.1 MW, the Fort Calhoun plant is the smallest nuclear unit in North America, lacking economies of scale. It is located on the Missouri River in eastern Nebraska and became operational in 1973. In 2003, the Nuclear Regulatory Commission extended its operating license through 2033.

The plant was surrounded by flood waters in 2011, when the reactor was idled for a scheduled refueling. Safety and security violations discovered after the flooding prevented it from returning to service until December 2013, following more than $140 million in repairs.

It has been managed since 2012 by Exelon Nuclear Partners. When operational, it provides 30% of OPPD’s net generation.

Burke said the decision was a difficult one and was “not reflective of employee or Exelon performance.”

“OPPD would make every effort to absorb as many employees as possible into other areas of the district, based on qualifications and open positions,” Burke said. “Retraining would be made available in cases where there would be strong potential for success.”

OPPD serves more than 310,000 customers in southeastern Nebraska. It has 3,080 MW of generating capacity, with two baseload coal-fired plants, one fueled by landfill gas and three peaking plants. It also purchases output from several wind farms.

The utility said it will consider constructing or purchasing additional gas, wind and solar generation “as necessary.”