Page 1698 – RTO Insider

December 15, 2015

Company Briefs

The El Paso City Council last week voted unanimously to reject a $71.5 million rate increase by El Paso Electric.

Unless the city and utility can negotiate a settlement by Dec. 15, which is the deadline for reaching an accord with the city, the dispute will head to the Public Utility Commission of Texas for a final decision.

The utility filed a rate increase request with the city on Aug. 10, asking for a 12% increase for residential and small commercial customers, a 24% rate increase for solar residential customers and large increases for government agencies and other classes of customers.

More: El Paso Times

Rockland Capital Illinois Plant $2 Million Behind on Taxes

Rockland Capital, owner of the Grand Tower Energy Center power plant in Illinois, told The Southern Illinoisan in a statement last week that it is “not in the financial position to make tax payments based on the current assessment.” The company has failed to pay more than $2 million in property taxes on the 490-MW combined-cycle plant to Jackson County.

Rockland has argued for a 93% reduction in assessed value, from $100 million to $7 million. The company has been battling the county on the issue for two years. “Despite our repeated attempts to negotiate in good faith — including initiating mediation efforts with a well-respected retired Illinois judge of many years and making the assessor’s office aware of the plant’s difficult financial situation — our efforts have been rebuffed,” the company said in a statement.

Jackson County Treasurer Sharon Harris-Johnson said the company has until Jan. 18 to pay the tax arrearage, which is accumulating interest. If it does not pay its back taxes by the deadline, she said, it will be subject to a tax sale.

More: The Southern Illinoisan

OCC Hearings Begin for PSO’s $169M Rate Case

The Oklahoma Corporation Commission is focusing on details of a settlement Public Service Company of Oklahoma entered into with EPA over compliance with emissions rules, which is at the heart of the utility’s request to raise rates to pay for $169 million in environmental upgrades.

Steve Fate, PSO’s director of business operations support, said the utility entered into the EPA settlement to resolve part of a federal plan imposed on Oklahoma for regional haze. The utility plans to retire one coal unit in 2016 and another coal unit in 2026 at its Northeastern Station plant to comply with the regulations.

The utility is seeking to boost customer bills by 14% next year to cover its compliance costs.

More: The Oklahoman

Xcel’s SPS Labor Force Requesting Market-Equity Raise

More than 800 employees of Xcel Energy’s Southwestern Public Service subsidiary are requesting a wage increase to keep pace with the pay of Xcel’s other operating units, a demand the company called “unreasonable and unachievable.”

Employees represented by the International Brotherhood of Electrical Workers say they are not being paid equal wages compared to employees at Xcel’s other units, including Denver-based Public Service Company of Colorado.

“Workers in our area have not had an increase in two years,” said Robert Melton, IBEW business manager. “Workers here just want to be paid equal to what everyone else with their skills are being paid.” Negotiations are ongoing.

More: Carlsbad Current-Argus

Kemper Project Costs Continue to Climb

Mississippi Power has announced it will spend another $62 million finishing construction on a coal-gasification power plant in eastern Mississippi, pushing the total cost to almost $6.5 billion.

The company said ratepayers would not be liable for the new set of overruns, which were needed to finance changes and repairs after the Kemper County power plant underwent test runs. About $4.2 billion of the project is eligible for recovery in rates. Southern Co., the utility’s parent, will write down $2.3 billion of the $6.5 billion project.

More: Associated Press

Municipal-Owned Power Plant Shuttered After 100 Years

The municipally owned Peru power plant, a coal-fired generator that has stood since 1911 and was the sole supplier of electricity to the northern-central Indiana city until the 1970s, will retire on Jan. 1.

The Peru Utilities Service Board voted Dec. 4 to shut down the plant, saying it would have been too expensive to upgrade it to comply with regulations introduced under the Clean Power Plan. The plant has only operated for a few days a year since 2009.

Now Peru’s utilities board needs to decide whether to demolish or mothball the facility. A study commissioned by the utility has estimated it would take $4.8 million to raze the plant, while a mothballed facility would cost $140,000 annually to maintain.

More: Kokomo Tribune

NRG to Shutter Illinois Coal Plant

nrg One of the Illinois coal-fired plants that NRG Energy bought out of bankruptcy last year won’t be bidding in PJM’s upcoming capacity auction and will likely be shuttered in a few years. The company said its 510-MW Will County Unit 4 is struggling to be competitive in a wholesale market dominated by low-cost natural gas and an increasing amount of low-cost renewables.

The unit is one of two remaining at the plant. Unit 3, a 251-MW coal-fired unit, was closed by NRG earlier this year. At that time, NRG said it would continue running Unit 4 as long as it was profitable. But the notice that the unit would not be participating in the capacity auction in practical terms means a permanent closure is imminent. The unit has 70 employees.

“After analyzing forecast market conditions, NRG has determined that we cannot justify continued operation of Will County Unit 4 … beyond May 2018,” NRG spokesman David Gaier wrote in an email.

More: Crain’s Chicago Business

GE to Supply Turbines for Pa. Power Plant

General Electric will supply two gas turbines for the 1,029-MW Caithness Moxie Freedom power plant in Luzerne County, Pa., which will generate enough power for nearly 1 million homes when it becomes operational in 2018.

The combined-cycle plant is being jointly developed by Moxie Energy and Caithness Energy.

GE Energy Financial Services is offering $592 million in senior secured credit facilities for the plant’s construction and operation.

More: Power Technology

PPL Names Bergstein Vice President, Treasurer

ppl PPL has named Joseph P. Bergstein its treasurer and vice president for investor relations, effective Jan. 1.

The 16-year veteran Bergstein was previously vice president for investor relations and financial planning. The move is part of a plan to consolidate functions within PPL’s corporate finance organization.

Bergstein takes the place of Mark Wilten, vice president, treasurer and chief risk officer, who will be leaving the company Jan. 31.

More: PPL

GM Assembly Plant to Tap Clean Energy in 2016

The General Motors assembly plant in Arlington, Texas, next year will derive 40% of its electricity from wind power, enough to build up to 125,000 trucks a year.

GM announced Dec. 10 it has signed an agreement with EDP Renewables of North America to purchase power from its Hidalgo Wind Farm in South Texas. Fifteen of the wind farm’s 260-foot tall turbines will be dedicated to GM’s energy needs, the company said.

More: The Dallas Morning News

December 15, 2015April 7, 2025

NERC: Tepid Demand, DR Growth Ensure Winter Readiness

By Ted Caddell

An increase in demand response, low load growth and market incentives have the nation’s power system in good shape heading into the winter, NERC said in its Winter Reliability Assessment last week.

“NERC-wide, sufficient margins are in place. Most assessment areas experienced little to no load growth, and demand response programs … continue to grow,” Tom Coleman, NERC’s director of reliability assessments, said during a conference call Thursday. “Winter of 2015 posed some challenges, but the system addressed these conditions, learning … from previous years’ lessons.”

nerc

“Total internal demand continues to trend downwards and is significantly augmented by the advancement of new energy efficiency programs, distributed energy resources and behind-the-meter generation (BTMG) resources that are being incorporated into planners’ load models and forecasts,” the report said.

While total DR is increasing 2.6 GW to almost 25 GW, NERC reported, resources available in the winter have doubled from about 10 GW to 20 GW.

“The addition of new demand response programs continues to help address potential resource adequacy concerns for areas during their winter peak,” according to the report. “These programs vary greatly in their availability and load reduction capability, but often provide the flexibility needed during extreme conditions.”

The winter-peaking Midwest Reliability Organization-Saskatchewan Power region boosted its winter DR to 244 MW from 158 MW a year ago. PJM, which formerly had only summer DR, has added a year-round product and will have 525 MW available for the winter peak, versus last winter’s 43 MW. (See related story, SPP: Ready for Winter.)

Coleman noted the increased coordination between natural gas suppliers and generators this year is a big improvement over the past two winters, when some generators in ISO-NE and PJM experienced difficulty obtaining gas in times of high demand.

He cited FERC’s approval of New England’s 2015/16 Winter Reliability Program, which established incentives for generators to procure on-site fuel before winter and another program encouraging generators to sign contracts for LNG. A dual-fuel testing and commissioning program will also provide incentives for generators.

NERC also noted readiness improvements in PJM, including pre-winter generator testing and winter preparation checklists as well as better communication on fuel status and improved coordination with natural gas pipelines.

Despite a net loss of 6,163 MW of installed capacity since last winter, NERC said PJM is in good shape, with an anticipated reserve margin of 40%, well above its own 15.6% requirement. (See PJM Prepared for Winter Load, Mild Temps Expected.)

“Because of the nature of the [three-year] forward capacity market in PJM,” NERC said, the benefits of its Capacity Performance rules “will not be seen until the winter of 2016/17.”

December 15, 2015

MISO Board of Directors Briefs

MISO’s Board of Directors last week approved the 2015 Transmission Expansion Plan, which calls for $2.75 billion in spending on 345 projects through 2024.

Board member Michael Evans said MTEP15 was shaped by more than 40 pages of stakeholder comments. “I think it got a thorough vetting and we’re happy to see the level of interest from stakeholders,” he said.

MTEP15 includes MISO’s first competitively bid project, the Duff-Coleman 345-kV line in Southern Indiana. MISO will fund the $67.4 million cost of the Duff-Coleman portion while PJM be responsible for the $85.3 million needed for the double circuit 345-kV tie-in to Rockport.

Evans said MISO’s competitive bidding is “an impressive process, but it’s also a new process so I expect we’ll encounter some bumps along the way.” He assured the room that the bidding, which begins next month, will comply with FERC Order 1000.

Evans added the projects that “slipped” and didn’t make the final plan were typical of the process and won’t affect reliability.

“Lest we forget, the volume of work that goes into this is huge. Some 60 meetings were held over the last 18 months to get this thing done,” Evans said.

MISO South’s share of approved projects represents $1.4 billion, more than half of the total portfolio.

It includes the $122.5 million East Texas economic project, a 230-kV transmission line from Lewis Creek to a new 345/230-kV substation and the rebuild of the Newton Bulk-Leach 115-kV line.

Also of note in the plan are Louisiana’s $122 million Schriever to Bayou Vista 230-kV line, the $114 million New Plains-National 138-kV line in Upper Michigan and the $97.8 million construction of two 120/41.6-kV substations to serve load in Ann Arbor, home of the University of Michigan.

“There’s an awful lot of good stuff in there. When your Christmas gifts are wrapped, you might want to read it,” board member Judy Walsh said of the 429-page document.

“These investments in the region will continue to position MISO for future challenges and changes in the industry,” said CEO John R. Bear. “As our region grapples with the Clean Power Plan and a shifting generation portfolio, MISO’s transmission planning efforts are even more important. Ensuring a robust transmission system will allow us to meet these challenges in a way that protects reliability.”

With the addition of MTEP15, transmission investment in the footprint will increase to 863 projects totaling about $12.9 billion since 2003.

Board OKs 2016 Budget; MISO Overspends by a Slight Margin in 2015

MISO will exceed its 2015 budget by as much as 1.3%, the Board of Directors was told last Thursday.

As of October, MISO had operating expenses of $185.2 million, an overrun of $2.4 million, reported Tonya Brown, executive director of finance and corporate services. The RTO is projected to spend an extra $1.8 million to $2.8 million by year-end.

During the first 10 months of 2015, spending on capital expenses came in under budget by $1.6 million or 7.8%; MISO spent $19.1 million instead of the allotted $20.7 million. However, the grid operator is forecasted to spend $24 million to $24.2 million instead of the budgeted $23.5 million by the end of the year.

The board unanimously approved the 2016 spending plan, a $225 million operating budget and a $31 million capital budget.

Cash reserves are predicted to drop over the next five years, reducing the expected $79 million MISO will have at the end of this year to $13.5 million in 2019 before rebounding to $46 million in 2020. Factors contributing to the reduction are the conclusion of recovery of depreciation on ancillary markets and the 2016 start of principal payments on debt.

Board member Thomas Rainwater reported that MISO’s costs have grown at a compound average rate of 3% while load has increased 30% over the past decade.

New Board Members Elected

MISO’s board agreed to add two new members to its Board of Directors: former general manager of Pasadena Water and Power Phyllis Currie and former vice president of transmission operations for Pacific Gas and Electric Mark Johnson. Additionally, board member and former chairman and CEO of the Boston Stock Exchange Michael Curran was re-elected to another three-year term, and board member Eugene Zeltmann, whose term expired, announced he would not seek another term. With the new appointments, MISO’s board expands from seven to nine seats.

— Amanda Durish Cook

December 15, 2015

Lead or Follow?

Tx Developers Urge ‘Proactive’ Role; OMS: Respect State Jurisdiction

By Amanda Durish Cook

CARMEL, Ind. — MISO stakeholders are deeply split over how proactive the RTO should be in helping its 15-state region comply with the Clean Power Plan.

At an Advisory Committee “hot topic” discussion last week, some stakeholders cautioned MISO against taking policy positions, while others said the RTO should help guide the states to the most economical compliance options.

“MISO is going to have to live with what the states decide,” said Texas Public Utility Commissioner Kenneth Anderson, whose state is among 11 in MISO whose officials have joined in legal challenges to the EPA rule. “Until real decisions are made, you run the risk of running into political minefields. Whether we do rate-based or mass-based [compliance], there are going to be very different consequences.”

No Advocacy Role

The Organization of MISO States also urged MISO to follow rather than attempt to lead the states. “Ultimately, MISO will be charged with incorporating the states’ decisions on CPP compliance into its markets, planning and operations. If those decisions result in some states choosing to ‘go it alone,’ some choosing to be trading-ready, some choosing rate-based or mass-based compliance, or taking legal action against the EPA, such decisions are the states’,” OMS said in its written comments. “MISO should focus on how to best operate a reliable system in these conditions.”

The End-Use Customer sector agreed that MISO’s role should “be limited to providing information and analysis on the cost and reliability impacts” of compliance options “rather than taking on an advocacy role.”

But others urged MISO to help steer the states, with the Environmental sector saying the RTO should “encourage states to adopt consistent, complementary plans that include coverage of new sources and facilitate broad trading opportunities.”

The Public Consumer sector said MISO should provide each state a comparison of rate-based and mass-based compliance “so the lowest-cost and lowest-risk compliance options are clearly identified.”

The Competitive Transmission Developers sector also pushed for a proactive role, saying “it is time for MISO’s role to shift from information dissemination to collaboration and active planning to facilitate state compliance efforts.”

“Without a proactive and accelerated RTO planning effort to ensure necessary transmission infrastructure can be put in place across the region, the ability of each member state to meet compliance requirements could be heavily restricted (if not jeopardized) due to reliability concerns, in addition to the potential loss of efficiencies currently provided by the MISO market,” it said.

Stakeholders also were divided on whether MISO should file comments with FERC on EPA’s proposed federal implementation plan. “MISO has not made any decisions on if we will comment,” said Kari Bennett, MISO’s senior corporate counsel.

Bennett said MISO will not seek to advocate or condemn any state compliance plans and that modeling would be based on “dispassionate calculations.”

But MISO Director Eugene Zeltmann said it might be difficult to entirely wipe out any public policy in CPP modeling. “There’s going to be some very sterile modeling going on,” he said.

MISO Role in Trading

Although there is wide agreement that compliance will be least costly if it includes a broad regional emissions trading program, MISO’s role in trading is uncertain.

The Transmission Owners sector said MISO should look to existing programs such as the Midwest Renewable Energy Tracking System, rather than developing its own trading platform. “There are existing markets … for trading allowances and credits,” the TOs said. “These markets will perform very well.”

The Independent Power Producers sector said MISO “should not have a role in implementing any multi-state implementation plans,” saying both the Regional Greenhouse Gas Initiative and California’s cap-and-trade program “require no interface with the RTO/ISOs beyond allowing suppliers to price the cost of emissions compliance into their offers.”

Many Unknowns

Next month, MISO expects to release its near-term analysis, which will evaluate the implications of various compliance paths based on models used in prior analyses of the draft CPP, with updates reflecting the final rule.

The mid-term analysis, expected to run through June, will use new models based on the most relevant compliance paths from the near-term study to determine likely resource buildouts and their locations under three separate futures. It will be the foundation for transmission development under the 2017 MISO Transmission Expansion Plan.

A long-term analysis, which will run through late 2018, will seek to develop transmission overlays needed to implement state compliance plans. (See MISO Unveils CPP Study Scope, Will Deliver Preliminary Near-Term Results Next Month.)

With state compliance plans unknown, there are limits to what MISO can model, said Clair Moeller, MISO executive vice president of transmission and technology.

Most states are expected to seek a one-year delay from EPA, meaning their compliance plans won’t be filed until November 2017, when MISO will be in the middle of its long-term analysis. EPA will impose a federal plan on states that fail to present an acceptable plan of their own.

Detailed modeling would have to wait “until the states start to tip their hand one way or the other,” Moeller said. “We’re going to run out of time like we always do. There’s going to be a panic in 2017, but we’re going to do all we can.”

Challenges will arise to fit state plans into regional markets, stakeholders said. Several AC members pointed out that Wisconsin is the only state within MISO whose borders are completely within the RTO’s footprint.

“I don’t think we’re going to model our way into quantitative comfort,” Director Michael Curran said. “We may model ourselves to a level of frustration with each other.”

More transmission will likely be needed under any compliance scenario, several stakeholders said.

“MISO should not wait for all state plans to be filed before beginning work on the transmission studies, including overlay studies,” the TOs said, urging MISO to quickly identify “no regrets” transmission projects likely to be needed under a variety of scenarios.

MISO’s Environmental sector pointed out that the Midwest is home to the nation’s best onshore wind resources. “Planning to quickly, affordably and reliably tap into these wind resources and deliver them to market can be done more effectively if interregional planning processes are improved,” it said. “More action is necessary to identify the transmission necessary to access and transport the energy to MISO and other regions.”

Modeling Priorities

Some stakeholders expressed dissatisfaction with MISO’s modeling priorities.

The TOs said MISO should focus on “providing an impartial comparison of the different means and approaches to full compliance and its impacts on reliability and efficiency of the grid.” They said that scenarios for partial and accelerated compliance would provide only “marginal” benefits.

“The accelerated compliance scenario, while still possible, is highly unlikely, even with technology breakthroughs, given the short timeline,” it said. “Even if, ultimately, more aggressive long-term goals for greenhouse gas abatement were to be adopted, they would likely be sought through steeper reductions in the outer years. Second, a partial compliance scenario may have some value, particularly if scoped as a delayed implementation scenario to account for legal challenges, but MISO should avoid spending too many resources and/or time on this.”

The End-Use sector said MISO should increase its coordination with neighboring SPP and PJM and “benchmark” the results of its analyses against those of the other regions. The sector said MISO should expand its modeling to include not only cost estimates for generation and transmission that may be needed, but also an evaluation of whether the region has sufficient natural gas infrastructure to accommodate the anticipated increase in gas-fired generation.

The Environmental sector said MISO should “more comprehensively model compliance strategies that rely on increasing energy efficiency (EE).”

“Without modeling high EE scenarios, states will not be able to understand the cost and emissions implications of expanding their EE programs as a strategy to comply with the CPP,” it said. “For example, in rate‐based compliance approaches, excluding EE from the supply will artificially constrain the supply of emissions reduction credits (ERCs) and increase ERC prices. Modeling EE simply as lower demand growth would not allow for its incorporation into a rate‐based plan in this manner, and thus would skew model results.”

Changes Coming

The Transmission-Dependent Utilities sector said MISO may need to change some market rules. It said a seasonal capacity construct, now under discussion, could aid compliance. (See MISO Proposes Two-Season Capacity Market, Appoints Team to Address Ill. Zone.) “Entities may choose to only run their coal-fired units during peak demand periods in the summer, and use natural gas as much as possible in shoulder periods,” it said.

It also said MISO should be prepared to replace spinning reserves, black start services and reactive power services provided by baseload units that may retire or limit operations.

The shift from coal- to gas-fired generation argues for a move to a multi-day resource commitment, it said.

“The current next-day economic commitment process can lead to higher costs by not committing long-lead time resources, which are economical over longer periods. A longer commitment process will help to address this issue and improve the economic operation of gas-fueled generation by providing a longer lead time to procure fuel.”

The competitive transmission developers said MISO should “conduct accelerated discussions” with stakeholders on how the RTO will allocate costs of transmission improvements needed for compliance. “Currently, there is too little flexibility in the MISO Tariff to allow for sub-regional or state-based cost allocation for public policy projects, which could impede necessary development if left unaddressed,” they said.

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

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.