Page 1697 – RTO Insider

December 15, 2015

Federal Briefs

The landmark climate deal reached in Paris on Saturday will have wide-ranging impacts on utilities and other industries, analysts say. More than 190 countries pledged to reduce their emissions of carbon and other heat-trapping gases following two weeks of negotiations.

Investment funds will move their portfolios from coal and oil to renewables — reflecting utilities’ shifting generation mix — while inventors will seek breakthroughs in energy storage and carbon capture technologies, and automakers will have to expand production of electric cars.

Business leaders have long complained that the lack of a clear political message on global warming was hamstringing their investment decisions.

“We have an opportunity to build a new economy, and business is poised to help make it happen,” said Richard Branson, CEO of the Virgin Group. “The ‘Paris effect’ will ensure the economy of the future is driven by clean energy.”

“It’s very hard to go backward from something like this,” agreed Nancy Pfund, managing partner of DBL Partners, a venture capital firm. “People are boarding this train, and it’s time to hop on if you want to have a thriving, 21st-century economy.”

The success of the Paris meeting was in stark contrast to the failure of the 2009 talks in Copenhagen. But the commitments made last week won’t be enough to meet the agreement’s goal of keeping global warming “well below” 2 degrees Celsius (3.6 degrees Fahrenheit).

More: The New York Times; Associated Press; The Washington Post

NRC Grants 20-Year Extension to FirstEnergy’s Davis-Besse

Despite its own characterization of the plant’s history as troubled, the Nuclear Regulatory Commission issued a 20-year license extension to FirstEnergy’s Davis-Besse nuclear plant in Ohio. NRC reviewed the plant’s operational record for five years, substantially longer than most license-extension reviews.

“We had a couple of issues that took a little longer to understand the full ramifications,” said Sam Belcher, FirstEnergy’s chief nuclear officer.

Davis-Besse experienced a partial loss of coolant in 1985, cracks in its containment building and serious corrosion of the plant’s reactor head in 2002, contributing to its becoming a target of anti-nuclear activists such as Terry Lodge, who called Davis-Besse “a contrivance of regulatory neglect and corporate welfare.”

More: Toledo Blade

NRC Approves Continued Indian Point Operations

The Nuclear Regulatory Commission has told Entergy it can continue to operate the Indian Point nuclear power plant’s Unit 3 under its existing license while its license renewal review continues.

Unit 3’s 40-year license would have expired at midnight on Saturday had Entergy not applied for a license renewal eight years ago, the company said. Entergy can continue to operate the plant in Buchanan, N.Y., under the federal government’s “timely renewal” provision and until NRC makes a final determination on the company’s license renewal request.

The other operating plant at Indian Point, Unit 2, received a similar approval from NRC in September 2013 prior to it entering the period beyond its initial 40-year license.

More: Entergy

NRC Says Indian Point Trip due to Bad Fan Breaker

A faulty electrical breaker controlling a roof fan caused last week’s trip at Indian Point Unit 2, according to the Nuclear Regulatory Commission.

The commission said operators at the New York plant manually shut down the reactor Dec. 5 when the faulty breaker caused a drop in voltage to the mechanisms controlling about 10 of the reactor’s control rods. That caused those rods to drop into the reactor, slowing the reaction and trigging a shutdown.

Operations at neighboring Unit 3 were unaffected.

More: Cortlandt Daily Voice

FERC Tells Atlantic Coast Pipeline to Find Alternate Routes

ferc FERC has told the developers of the $5.1 billion Atlantic Coast Pipeline project that they should look for alternative routes through the Monongahela and George Washington national forests on the West Virginia-Virginia border.

“To ensure that a complete and thorough evaluation of the ACP is presented in the draft environmental impact statement, we request that Atlantic identify and assess an alternative pipeline route across the national forests,” FERC said in a letter to Dominion Resources, the pipeline’s developer. FERC issued the directive after consulting with the U.S. Forest Service.

Dominion said it was not surprised by the FERC notice. “Our goal from the beginning has been to develop a route that meets the critical energy needs of our public utility customers with the least impact on people, the environment and historical and cultural resources — including locations where it crosses the working forests,” a Dominion spokesperson said. The 542-mile pipeline would deliver natural gas from Appalachian shale formations to North Carolina.

More: Charlotte Business Journal

FERC Turns Down Request for Further Pipeline Study

FERC has turned down a request by landowners, local governments and environmental groups in Virginia and West Virginia to conduct a cumulative impact study of several proposed pipeline projects that would cross the region.

FERC said there was no precedent for such a study, which had been requested by the Blue Ridge Land Conservancy and other groups. Advocates say such a study could establish standards for multiple projects being cut through wilderness and farmlands.

“With the recent exponential increase in applications to FERC for new interstate pipelines to transport Marcellus Shale natural gas, FERC’s traditional project-by-project [National Environmental Policy Act] review has proven increasingly ineffective,” said the Water and Power Law Group.

More: The News Virginian

FERC to Consider NEXUS Ohio-Canada Gas Project

FERC is being asked to issue a certificate of convenience to a proposed natural gas pipeline that would deliver shale gas from Ohio to customers in Michigan and Canada.

The NEXUS Gas Transmission project would run 255 miles through Ohio and terminate at the Dawn Hub in Ontario. Spectra Energy is working with other pipeline, gas storage and utility companies to develop the project.

“The NEXUS project will play a key role in helping the U.S. transition to cleaner sources for generating electricity — including new power plants fueled by natural gas — as coal plants are retired due to their age and environmental regulations,” said David Slater, DTE Energy’s president of gas storage and pipelines.

More: Daily Jeffersonian

NRC Allows Entergy to Shrink Vermont Yankee Emergency Zone

The Nuclear Regulatory Commission has agreed to allow Entergy to cease to maintain the 10-mile radius emergency planning zone around its retired Vermont Yankee nuclear generating station. Entergy applied for permission to shrink the emergency zone to just the plant and its perimeter.

NRC spokesman Neil Sheehan said the company had proved it was able to contain any radiological release from the on-site spent fuel storage at the plant, which shut down at the end of 2014.

“Once the reactor is shut down, you no longer have to worry about the sudden kind of event where there’s a rupture of a steam line and there has to be immediate actions taken to protect the public,” Sheehan said. “They had to be able to demonstrate to us that they would be able to do whatever is necessary to make sure that that pool maintains its integrity so that that pool is protected.”

More: Vermont Public Radio

December 15, 2015

Study: Loss of Nuclear Plants Would Cost $1.7B Annually

By William Opalka

New York electricity customers would pay about $1.7 billion more annually over the next decade if the nuclear fleet operating on Lake Ontario shuts down, according to a new study by The Brattle Group.

The report, released Dec. 7, was prepared for three unions representing utility workers and building tradesmen in western New York.

The backdrop is the proposed shutdown of Entergy’s James A. FitzPatrick plant and the eventual closing of the R.E. Ginna plant, owned by Exelon, when a contract providing ratepayer subsidies runs out in 2017. (See Ginna Lifeline to End in 2017; Profits After ‘Unlikely’.)

nuclear Also included in the study is Exelon’s two-unit Nine Mile Point. The company has not indicated that the plant is in danger of closing but said its environmental attributes need to be recognized in the design of the wholesale market.

Nuclear supporters are trying to keep the plants running. Gov. Andrew Cuomo also has some ideas on how to keep the plants operating for the next 15 years for their air emissions benefits while New York transitions to more renewable and distributed energy in its power system. Details could be released at Cuomo’s State of the State address in January.

The three plants, with four reactors, have a combined generating capacity of 3,345 MW. They represent 7% of NYISO’s capacity but 15% of its electricity production.

The study said the plants lower wholesale electricity prices and mitigate the state’s ever-increasing reliance on natural gas for power generation. Without upstate nuclear, natural gas’ share of generation would rise from the current 40% to 54%, it said.

“This alternative generation mix would mean higher average electricity prices in New York, driven in part by energy market effects, but perhaps more importantly by the effect on NYISO capacity markets,” the study said. The power plants contribute approximately $3.16 billion to the state’s gross domestic product, account for nearly 25,000 full-time jobs (direct and indirect) and provide other benefits, such as avoiding 16 million tons of carbon dioxide emissions annually, according the report.

The plants also contribute $144 million in net state tax revenue annually, including more than $60 million in state and local property taxes.

The report was prepared for the International Brotherhood of Electrical Workers’ Utility Labor Council of New York, the Rochester Building & Construction Trades Council and the Central-Northern New York Building & Construction Trades Council.

December 15, 2015

AEP Ohio Reaches PPA Settlement with PUCO Staff, Sierra Club

By Ted Caddell

aep — AEP Conesville Plant (Source: Ohio Citizen Action)

AEP Ohio has reached a settlement with Public Utilities Commission of Ohio staff and others on an eight-year power purchase agreement, winning the support of the Sierra Club with a promise to double the state’s wind generation and nearly quintuple its solar capacity.

The settlement provides guaranteed income for the output of American Electric Power’s 2,671-MW ownership share of nine plants, as well as the company’s 423-MW contractual share of Ohio Valley Electric Corp.’s generating fleet, until May 2024, the company announced Monday.

The Sierra Club, which had rejected a similar deal reached by FirstEnergy two weeks ago, is one of 10 parties that signed on to the settlement or agreed not to oppose it. (See FirstEnergy, PUCO Staff Reach Settlement on PPA for Ohio Merchant Plants.)

AEP said the agreement, which still needs to be approved by PUCO, would raise a typical residential customer’s bill by 62 cents/month. But when coupled with its recently approved Electric Security Plan, rates will be $9/month less than rates a year ago, the company said.

AEP also predicted that the settlement agreement would result in savings to consumers of $721 million over its eight-year life.

Opponents say AEP’s projections assume an unlikely increase in natural gas costs in the later years. The Ohio Consumers’ Counsel (OCC) has predicted that the deal would cost consumers an extra $2 billion.

Minutes after AEP announced the settlement agreement, the OCC issued a release criticizing it.

“It’s a sad day for AEP’s consumers when, 16 years after the 1999 deregulation law, the government is being asked to impose charges on consumers for a bailout of deregulated power plants,” said Consumers’ Counsel Bruce Weston, who also opposed the FirstEnergy agreement. “Consumers should not be charged a penny more than the cost of power in the market.”

Many of the same companies and associations who are denouncing the settlement also criticized a similar agreement with FirstEnergy. Dynegy and Talen Energy have threatened to sue over the FirstEnergy deal, a warning repeated by Dynegy CEO Robert Flexon on Monday. “Dynegy will continue to fight for market-based policies that treat all forms of power generation equally through advocacy and litigation, if necessary, to prohibit these power purchase agreements from being enacted,” Flexon said. (See Merchant Generators Lead Opposition to FirstEnergy-Ohio Settlement.)The PJM Power Providers Group (P3) and the Electric Power Supply Association also blasted the agreement.

“It just doesn’t make sense that in the face of overwhelming testimony that competitive markets are working to push electricity rates to historically low levels in Ohio that the PUCO staff would yet again agree to a misguided proposal that will not improve reliability, will not reduce volatility, will force consumer to pay more for power and will drive innovation out of the state,” P3 President Glen Thomas said.

Environmental Support

Part of the AEP agreement is a commitment to retire or convert some of its coal-fired generators to natural gas. It also includes commitments to develop 900 MW of wind and solar projects, continued support for energy efficiency programs and up to $100 million in customer credits.

It was this combination of sweeteners that brought the Sierra Club into the fold. While the group was harsh in its criticism of the FirstEnergy deal — saying “PUCO’s staff decision to move forward with a backroom deal to bailout FirstEnergy’s aging power plants is insulting to Ohio utility customers” — it came out in support of the AEP plan.

“The proposed stipulation reflects a very difficult yet pragmatic discussion between AEP and Sierra Club,” senior campaign representative Daniel Sawmiller told The Columbus Dispatch. “While nobody will call this deal perfect, we’re proud of what it accomplishes toward reinvigorating Ohio’s clean energy economy and moving beyond coal.”

The group was swayed by AEP’s commitment to develop 500 MW of wind generation and 400 MW of solar within five years.

Ohio’s current installed wind capacity of 435 MW ranks 26th in the nation and contributes less than 1% of its in-state generation, according to the American Wind Energy Association. Another 259 MW is under construction.

The state has 106 MW of solar, ranking it 20th in the country, according to the Solar Energy Industries Association.

The nine AEP generating stations covered by the agreement are: Cardinal Unit 1 in Brilliant; Conesville Units 4-6 in Conesville; Stuart Units 1-4 in Aberdeen; and Zimmer Unit 1 in Moscow.

The environmental commitments to its plants cover converting Conesville Units 5 and 6 to co-fire natural gas by Dec. 31, 2017, and retiring, refueling or repowering Conesville Units 5 and 6 and Cardinal Unit 1 to only use natural gas by the end of 2029 and 2030.

In addition to PUCO staff and the Sierra Club, AEP said Ohio Partners for Affordable Energy, Ohio Energy Group, Ohio Hospital Association, Mid-Atlantic Renewable Energy Coalition and three competitive retail energy suppliers had agreed to sign or not oppose the settlement.

“This agreement addresses many of the concerns raised by a diverse group of parties including advocates for low-income customers, environmental organizations, industrial and commercial customers and competitive energy suppliers,” said Pablo Vegas, CEO of AEP Ohio.

The Ohio Environmental Council was among those not swayed. “We’re still very much opposed to this idea that consumers are being forced to pay for dirty energy,” Trish Demeter, the council’s managing director of energy and clean air programs, told The Columbus Dispatch.

December 11, 2015

Divided PURA Approves Utility Takeover

A divided panel of Connecticut regulators on Wednesday gave final approval to Iberdrola USA’s $3 billion takeover of UIL Holdings.

The state’s Public Utilities Regulatory Authority voted 2-1 in favor of the deal, which it had tentatively approved last month. (See Connecticut Regulators Poised to OK Iberdrola Acquisition of UIL.)

In a dissenting opinion, authority member Michael Caron said the deal presents “too many unknowns” for regulators and the state’s ratepayers.

“Iberdrola is a multi-national conglomerate that is currently engaged in regulated and unregulated activities,” he wrote. “Consequently, parts of Iberdrola’s business may be more inherently risky than its regulated utilities. These risks outweigh the minimal public benefits provided in the settlement agreement.”

Iberdrola agreed to regulators’ demand for “ring fencing” of the company’s state operations from its other domestic and international holdings. But Caron said that the company’s responsibilities to its shareholders overall would undermine those protections for Connecticut ratepayers.

Caron also said Iberdrola’s previous ownership and sale of two Connecticut natural gas distribution companies showed a lack of commitment to the state.

In a statement, PURA Chairman Arthur H. House said the deal was in the public interest and overcame objections that officials had to the first proposal last summer.

“While their first proposal had many positive aspects, Iberdrola and UIL took to heart the message we sent in our preliminary ruling, measurably improving both the public benefit content of their proposal, and also making specific, measurable commitments that ensure the flow of benefits to utility ratepayers,” he wrote.

PURA Vice Chairman John Betkoski joined House in approving the acquisition.

The deal had won the endorsement of the state’s Consumer Counsel in September.

The deal must still be approved by UIL shareholders and Massachusetts regulators, who have jurisdiction over UIL’s natural gas distributor Berkshire Gas. The companies have asked that state’s Department of Public Utilities to rule by Dec. 18.

December 8, 2015

ITC Accused of Overcharges in Depreciation Dispute

By Amanda Durish Cook

ITC Midwest is overcharging its customers for network upgrades because it isn’t applying for tax breaks to which it is entitled, customers and Iowa officials told FERC last week.

Among the projects affected is Wisconsin Power and Light’s 201-MW Bent Tree Wind Farm in southern Minnesota.

In an unexecuted facilities services agreement filed with FERC, ITC said it needs $38.8 million in network upgrades to support Bent Tree’s generation. It sought to bill WPL $418,020 monthly over 25 years.

WPL asked FERC last week to reject the rates, claiming the charges are excessive because they fail to reflect the “bonus” depreciation that ITC could claim on its federal taxes (ER16-206).

WPL’s sister company, Interstate Power and Light in Iowa, filed a motion to intervene on Nov. 24, saying it could face an identical situation over its Marshalltown Generating Station, which is interconnecting into ITC’s transmission system in Iowa.

“IPL has estimated that ITC Midwest’s annual revenue requirement is roughly $18 million higher in 2015 than it would have been had ITC Midwest taken available bonus depreciation in prior years in which it was eligible to do so. This results in an ITC Midwest transmission rate which is approximately 5% higher, unnecessarily increasing charges to ITC Midwest’s customers — including IPL and its customers,” IPL stated in its motion.

The Iowa Office of Consumer Advocate, Iowa Consumers Coalition, Iowa Utilities Board and Resale Power Group of Iowa have all filed to intervene in the matter.

“The IUB also understands that when bonus depreciation is utilized, it is done so on all capital investments within a given class of assets in a given year, not just selected projects. Thus, ITC Midwest’s choice to not utilize bonus depreciation will affect not only the Bent Tree or Marshall Generating Station network upgrades, but could affect all capital investments in the asset class, including investments elsewhere in the ITC Midwest transmission system, which could directly affect Interstate Power and Light’s customer costs of transmission service,” the Iowa Utilities Board said.

Likewise, the Iowa Consumers Coalition said ITC should “articulate a sound rationale for not electing to take bonus depreciation.”

ITC did not respond to a request for comment.

December 8, 2015

Merchant Generators Lead Opposition to FirstEnergy-Ohio Settlement

By Ted Caddell

In recent policy disputes over capacity markets and energy price caps, FirstEnergy and the independent power producers of the Electric Power Supply Association have usually been on the same side.

When EPSA won a federal appeals court ruling voiding FERC’s authority over demand response last year, FirstEnergy asked the commission the same day to prevent DR from being included in PJM’s capacity auction.

But when the Akron-based utility announced last week that it had reached a settlement with the staff of the Public Utilities Commission of Ohio to secure guaranteed rates for several of its merchant plants, the company found itself under attack by many of its former allies.

By Thursday, EPSA had corralled Dynegy, Talen Energy, the PJM Power Providers Group (P3), the Sierra Club of Ohio, AARP and others in a coalition blasting the deal. Dynegy and Talen threatened to sue.

“The fault of FirstEnergy’s inability to compete in Ohio lies with FirstEnergy and it should not be dependent on the citizens and businesses of Ohio to provide a bailout,” said Robert C. Flexon, CEO of Dynegy, which increased its stake in PJM with its purchase of 12,500 MW of generation from Duke Energy and Energy Capital Partners earlier this year. (See Dynegy Wins FERC OK for $6.25B Duke, Energy Capital Partners Generation Deals.)

“Dynegy will pursue all available avenues, including litigation, to prohibit the power purchase agreement from being enacted so as not to compromise the competitive market design, and we strongly encourage the PUCO commissioners to oppose and vote down this adverse anti-market public policy.”

Dynegy said that FirstEnergy is already enjoying the benefits of the wholesale market and shouldn’t need any further assistance.

“Recent market awards indicate that FirstEnergy is already set to receive significant revenue for capacity at all of their Ohio plants for the next three years,” Dynegy said. “According to FirstEnergy’s own data from their recent investor presentation at the Edison Electric Institute’s Financial Conference, FirstEnergy’s fleet has been awarded more than $2.3 billion in revenues over the next three planning years from the PJM capacity auction with all of their generating plants clearing the most recent capacity auctions, which is significantly more than the amount expected at the time of FirstEnergy’s original subsidy request. As part of the award, FirstEnergy’s plants are now obligated to run through May 31, 2019, without the PPAs.”

Reliability Threat

FirstEnergy has said that it needs the income guarantees, in the form of PPAs for its Davis-Besse Nuclear Power Station, the W.H. Sammis coal-fired plant and its share of Ohio Valley Electric Corp.’s generation output, to keep them profitable.

American Electric Power has a similar proposal pending before the Ohio commission. Without the guarantees, the companies say, they might have to retire their plants, threatening system reliability.

Sixteen parties, including PUCO staff and civic groups, signed on to the proposed settlement filed with the commission last Tuesday (14-1297-EL-SSO). Several other organizations, including the Office of the Ohio Consumers’ Counsel, rejected the deal and joined in a motion to reopen the record.

FirstEnergy’s first proposal, which PUCO staff rejected earlier this fall, called for income guarantees for 15 years. The settlement seeks income guarantees for eight years. Ratepayers would make FirstEnergy whole if its generators were not profitable based on their capacity and energy sales in the competitive market.

Although PUCO staff approved the settlement, it still needs approval of the commission. FirstEnergy said it expects the commission to hold hearings on the proposal early next year.

Picking Winners and Losers

Talen joined Dynegy in promising to contest the deal in court if it is approved by the commission.

“As you are aware [PPL, one of Talen’s predecessors] led successful legal challenges in the federal courts against generation subsidy initiatives in New Jersey and Maryland,” Talen spokesman Todd Martin said Thursday. Before PPL’s generation assets were spun off to form Talen, the company won court rulings voiding PPAs obtained by Competitive Power Ventures for two merchant plants. (See CPV Md. Plant Goes Forward Despite FERC Ruling.)

“We believe states with competitive electricity markets must let those markets operate without interference or subsidies, and should not in effect be picking winners and losers,” Martin said.

P3 President Glen Thomas said PUCO staff’s “about face” represents “corporate welfare at its worst.”

“Forcing customers to buy overpriced electricity from uncompetitive plants to deliver windfall profits to FirstEnergy is a holiday offering that only the Grinch could support,” said Trey Addison of AARP Ohio.

“This bailout would leave Ohio locked into outdated and costly coal and nuclear plants, when we should instead be working to transition to a cleaner and more competitive energy system,” said Shannon Fisk, managing attorney with Earthjustice. Fisk was involved in settlement negotiations on behalf of the Sierra Club but withdrew in protest just before Thanksgiving.

Also weighing in was anti-nuclear group Beyond Nuclear, which blasted any deal that would result in the continued operations of FirstEnergy’s Davis-Besse nuclear plant. “The ratepayers of Ohio would be gouged additional billions of dollars on their electricity bills to prop up the uncompetitive Davis-Besse atomic reactor, effectively being forced to fund 20 more years of radioactive Russian roulette at the problem-plagued atomic reactor,” Beyond Nuclear spokesman Kevin Kamps.

$20/MWh Premium

Despite the opposition, UBS analysts predicted last week that the commission will approve the PPAs, which the analysts valued at $68/MWh.

That would be $20 MWh above market prices, based on Ohio’s most recent auction for default service. PUCO in November accepted the results of AEP Ohio’s third wholesale auction to determine the default price through May 2018, at $48.29/MWh. That price will be blended in with result from other auctions to determine the price-to-compare for June 1, 2016, to May 31, 2018. The $48.29 price was the result of a 13-round auction with six competitive suppliers participating.

On Monday, UBS upgraded AEP to “buy” on the expectation that it will win PUCO approval of its deal.

FE: Looking out for Ratepayers

For its part, FirstEnergy said it wasn’t surprised to see the blowback from competitors.

It said it alone is looking out for Ohio’s ratepayers. Although residential ratepayers would pay an extra $3.25 to $3.50 a month during the first year of the deal, the company claims it will produce overall savings of about $560 million. FirstEnergy’s projections, which assume sharply higher natural gas prices in the latter years of the deal, have been widely disputed.

“FirstEnergy has stated from the outset that customers will likely see a monthly charge in the first three years under this arrangement, with the charges converting to credits for customers for the remainder of the eight-year term,” FirstEnergy spokesman Doug Colafella said Friday.

“Out-of-state power producers opposing our plan are betting on sharply higher power prices in Ohio down the road, so naturally they would oppose putting safeguards in place to protect our customers,” Colafella said. “Our proposal is that safeguard.”

December 8, 2015

New Generation Boosts ERCOT’s Reserve Margins Through 2025

By Tom Kleckner

ERCOT will add about 9,300 MW of additional capacity by 2019, relieving concerns that the grid’s reserve margins would drop as load continued to grow, according to a new analysis.

The updated 10-year Capacity, Demand and Reserves (CDR) report released last week shows a continuing rise in planning reserve margins — topping 20% in the “next several years.” The Texas grid operator’s reserve margin has stood at 13.75% since December 2010.

The latest CDR shows about 6,250 MW of planned resources have become eligible to be included since the May 2015 report (a net of 3,660 MW after discounting wind nameplate additions). Planning reserve margins increased for all years except 2016.

Gas turbines and wind and solar farms account for much of the expected new capacity. ERCOT said solar capacity should increase from its current 193 MW of installed capacity to 1,789 MW by 2017. Nameplate wind capacity is expected to grow 45% to more than 4,200 MW over the same period, while natural gas capacity is projected to grow 1% to more than 51,000 MW.

ERCOT’s director of system planning, Warren Lasher, said the new generation was responding to the state’s continued growth. “We continue to see the demand for electricity here increase as more people and businesses move into Texas,” he said during a Dec. 1 conference call.

“The generation mix is also growing and changing,” Lasher said. He said some of the capacity growth could be offset by fossil unit retirements as “changing environmental rules begin to take effect.”

ERCOT forecasts a peak of more than 70,500 MW next summer, growing to almost 78,000 MW by summer 2025.

Two years ago, ERCOT was predicting a 20% decrease in its reserve margin. The grid operator had come perilously close to rolling blackouts during a blistering summer of 2011 and plant construction was practically nil.

Recent summer temperatures have not reached predictions and new capacity has come online since then, but ERCOT also revised its planning standards last year. Staff has incorporated growth trends in customer accounts, or premises, to better project regional demand growth.

“We have been able to provide a more accurate look at future demand and energy use,” said Calvin Opheim, ERCOT’s manager of load forecasting and analysis. “I’ve been very happy with how our new forecasting model has performed.”

The latest CDR forecasts peak loads averaging more than 500 MW higher through 2021 than the forecast used for the May CDR. ERCOT said the report is based on average weather over the past 13 years and includes additional electricity demand from a liquefied natural gas facility near Houston, which is scheduled to be fully operational by summer 2019.

The CDR’s data on generation comes from information provided by resource owners.

The report counts as capacity 4,700 MW of coal generation ERCOT expects to retire as a result of EPA’s Clean Power Plan and Regional Haze Program. The draft Regional Haze rule would require scrubber upgrades or retrofits at 12 coal-fired units by 2020. A final rule is expected in several months. The next CDR update is scheduled for release in May 2016.

ERCOT Sets Another New Wind Peak

ERCOT set a new record for wind generation Nov. 25 with 12,971 MW. That accounted for nearly 37% of the grid’s load at the time (9:10 p.m.).

The wind peak is ERCOT’s third since Oct. 21.

December 8, 2015

Entergy Rebuffs Cuomo Offer; FitzPatrick Closing Unchanged

By Ted Caddell

Entergy said last week it is sticking to its plan to close the FitzPatrick nuclear generating station, despite a rescue attempt by New York officials and an offer by Exelon to provide it fuel at cost.

Entergy announced last month that competition from low-cost natural gas generation will force it to retire the 838-MW plant in late 2016 or early 2017, when the plant would otherwise be shutting temporarily for refueling. (See Entergy Closing FitzPatrick Nuclear Plant in New York.)

Then came news that New York Gov. Andrew Cuomo wants the Public Service Commission to mandate that 50% of the state’s electricity come from renewable sources by 2030. Cuomo also called for incentives to keep the state’s nuclear plants operating until then. (See Cuomo: 50% Renewables by 2030, Keep Nukes Going.)

At the urging of Cuomo administration officials, Exelon agreed to acquire enough fuel for FitzPatrick and to give Entergy until next June to decide whether to use it based on the clean energy mandate. The PSC said that the proposed “fuel bridge” would allow Entergy to delay its decision without purchasing the $50 million worth of fuel now.

The offers weren’t enough to change Entergy’s mind.

“We have explored every legitimate commercial arrangement that might have changed the decision regarding Fitzpatrick’s retirement,” Entergy spokeswoman Tammy Holden told The Post-Standard. “There is no viable alternative left to consider. The plant will retire at the end of 2016 or early 2017, as we previously announced and have formally advised” the Nuclear Regulatory Commission.

December 8, 2015

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — PJM is drafting manual changes to document the parameter adjustment process under Capacity Performance rules.

The process allows a generation operator to request an adjustment if it believes its resource’s physical constraints will prevent it from meeting the parameters assigned by PJM.

Related revisions to Manual 11: Energy and Ancillary Services Market Operations will be presented for endorsement by the Markets and Reliability Committee this month.

At last week’s Operating Committee meeting, the RTO gave a presentation comparing the unit-specific parameter adjustment process with parameter limited schedule (PLS) exceptions.

Unit-specific adjustments would be permitted only because of ongoing, long-term operational limitations, said PJM’s Alpa Jani. Staffing, for example, would not qualify as a physical operating constraint.

PLS exceptions will be used to address short-term, temporary issues such as equipment damage.

Adjustment requests must be submitted to PJM no later than Feb. 28 before the delivery year. If the situation arises after that date, a waiver must be obtained from FERC.

Members also reviewed PJM’s new soak time parameter. Soak time is defined as “the minimum number of hours a unit must run in real-time operations, from the time the unit is put online (breaker closure) to the time the unit is at economic minimum or dispatchable.”

Until the new parameter is added to PJM manuals, adjustment requests similar to the soak time definition will be documented in the minimum run time parameter, and soak time will be noted in PJM internal documentation so it can be updated when a long-term solution is implemented.

In a related matter, the Market Implementation Committee approved an issue charge presented by Bob O’Connell on behalf of PPGI Fund A/B Development to study the process of requesting exceptions to the default parameter limited schedule. (See “Parameter Limited Schedule Exemption Process to be Reviewed” in PJM Market Implementation Committee Briefs.)

The work will be conducted as part of regular MIC meetings and will seek to identify improvements to existing practices for requesting and obtaining PLS exceptions. The group is expected to recommend manual and possible Tariff changes to the MIC by April.

Members Mull Performance Assessment Hour Notifications

PJM also gave the OC a presentation in response to stakeholder questions about performance assessment hours under Capacity Performance.

Generators are subject to steep penalties for failing to meet their capacity obligations during performance assessment hours — periods for which PJM has declared an emergency action. (Base capacity resources are exempt from such penalties except during the June-September summer peak season.)

Members discussed the best way for PJM to communicate the start and stop times of a performance hour. PJM is proposing to post the information in a banner on its Emergency Procedures web page. The notice would direct resource owners to a page where they will be able to find what is expected of them.

Several stakeholders said the information is so crucial that an alert should be placed on the PJM homepage.

PJM Assistant General Counsel Jen Tribulski cautioned that the placement of the notice on the site would not affect market sellers’ responsibility to perform.

“You’re excused from the penalties during the assessment hours if PJM didn’t call on you,” she said. “If we’ve called on you and we have not dispatched you down, you are expected to perform, regardless of whether there’s any notification on our website.”

Also under review is a new signal providing a “desired” basepoint that would be used during performance hours, but it’s not clear whether the signal would recognize a resource’s economic max or unforced capacity commitment.

Members also were told that all units must operate under their local reliability constraints, but having to do so will not excuse them from penalties for not meeting performance requirements.

Charter Approved for Metering Task Force

The committee approved a charter for a task force charged with reviewing metering policies and requirements and implementing best practices.

The group will consider classifications such as real-time telemetry versus revenue metering, generator versus transmission system metering and large generation versus distributed generation applications.

The task force will report recommended manual revisions to the OC. Its work is expected to take six months.

— Suzanne Herel

December 8, 2015

FERC Rejects SPP Proposal for Seams Transmission Projects

By Tom Kleckner

FERC last week rejected SPP’s proposal to create a new class of seams transmission projects, saying its plan was too broadly drawn (ER15-2705).

The commission’s Nov. 30 order said that SPP did not distinguish “the criteria to be deemed a seams transmission project from the criteria to qualify under SPP’s Order No. 1000 interregional processes.” It said the revisions “do not contain any prohibitions or limitations to support SPP’s assertions” that projects eligible for its Order 1000 interregional processes may not be classified and evaluated as seams transmission projects.

spp — FERC rejected SPP’s request to create a new class of seams transmission projects to supplement its approved highway-byway cost allocation.

SPP had proposed seams transmission projects as a new category to fill a gap in its transmission planning. It said the proposal would identify potential transmission projects that “may fall outside the Order 1000 interregional planning process or may not be eligible for cost allocation under SPP’s Order 1000 interregional processes,” such as projects involving external entities that are not neighboring planning regions.

SPP’s current rules designate transmission facilities of 300 kV or above as “highway” facilities whose costs are allocated entirely on a region-wide, postage stamp basis. Facilities between 100 kV and 300 kV are “byway” facilities, with two-thirds of the costs assigned to the host zone and one-third allocated region-wide. Projects below 100 kV are allocated entirely to the host zone.

SPP proposed to define a seams project as one operating at 100 kV or above and costing at least $5 million. It proposed a default regional cost allocation for such projects, with the RTO’s Board of Directors able to choose an alternate allocation at its discretion under certain conditions.

Xcel Energy protested the proposal, saying SPP had not provided “adequate analytical support” for the new category.

FERC agreed, saying the planning process for seams transmission projects “lacks clarity and does not adequately explain” how a seams project would progress from project identification to construction approval. It said SPP’s proposal for projects identified through joint special studies or coordination agreements “does not adequately define the methodology it will use to evaluate the project’s regional benefits.”

FERC said it wasn’t clear that regional review “will be transparent and include sufficient stakeholder involvement.”

The commission said, however, that SPP could make project-by-project filings for non-Order 1000 facilities that “may relate to seams concerns with an associated cost allocation and [justification for] the specific cost allocation.”

SPP legal staff expressed confusion over the ruling during a Dec. 3 meeting of the RTO’s Seams Steering Committee, saying it is “still digesting” the order.