FERC Orders MISO to Shift Electric Schedule

By Amanda Durish Cook and Tom Kleckner

FERC ordered MISO Thursday to post its day-ahead market results earlier, saying the RTO’s current schedule doesn’t allow gas-fired generators enough time to procure fuel.

The commission said MISO had failed to comply with Order 809, which moved the timely nomination cycle deadline for gas to 1 p.m. CT from 11:30 a.m.

The commission ordered MISO to move the posting of its day-ahead market results “at least” 30 minutes earlier to 12:30 p.m. CT. It also ordered the RTO to set a notification time for its forward reliability assessment commitment (FRAC) that is “sufficiently in advance” of the gas evening nomination cycle (ER15-2256 and EL14-25).

In separate orders, FERC accepted Order 809 compliance filings by SPP and CAISO. Order 809, issued in April, also added a third intraday nomination cycle. (See FERC Approves Final Rule on Gas-Electric Coordination.)

MISO Filing

MISO submitted a compliance filing in July that proposed posting day-ahead market results one hour earlier at 1 p.m. CT and the FRAC notification time two hours earlier to 5 p.m. CT. It also proposed moving its day-ahead market trading deadline one hour earlier during daylight saving time, so that the deadline would be 10 a.m. CT year-round.

The RTO also proposed reducing the day-ahead market solve time from four hours to three, saying that would meet Order 809’s requirement for posting post market results “sufficiently in advance” of the evening nomination cycle to allow gas-fired generators to obtain fuel and pipeline capacity while minimizing the impact on market participants.

MISO said the earlier publication of the day-ahead results would reduce costs by making up to 1,600 MW of longer lead notification generation capacity available. Similarly, the 5 p.m. CT FRAC notification time would allow consideration of up to 4,214 MW of longer lead notification resources.

MISO said its proposals were an effort to balance the Order 809 requirements against stakeholder preferences to maintain a day-ahead market deadline no earlier than 10 a.m. CT. Because most of its footprint operates in the Central Time Zone, MISO said, market participants use the morning hours to determine generation availability, develop forecasts and formulate bids and offers.

FERC not Persuaded

FERC said posting results ahead of the evening gas nomination cycle is not a substitute for posting in advance of the timely nomination cycle, which it said is “the most liquid time to acquire both natural gas supply and pipeline transportation capacity.” MISO’s proposed day-ahead notifications would overlap with the timely gas deadline, leaving generators no time to submit nominations.

The commission said MISO failed to demonstrate that moving its posting at least 30 minutes earlier “will be unduly burdensome or disrupt its markets.”

While MISO said it was not currently experiencing the gas scheduling challenges faced by PJM and the Northeast markets, FERC said, it had “recognized that in the future it could have scheduling difficulties as coal-fired plants retire.”

“For at least part of the year, MISO, like PJM, NYISO and ISO-NE, generally schedules its day-ahead market using Eastern Prevailing Time, which means that it has more time compared to SPP and CAISO during the morning hours to complete its day-ahead schedule in time to meet the 2 p.m. ET (1 p.m. CT) revised timely nomination cycle deadline,” the commission said. “Thus, it is not apparent how requiring MISO to move its day-ahead posting deadline in advance of the timely nomination cycle places an undue burden on the staffs of MISO and its stakeholders.”

The commission acknowledged that MISO’s stakeholders generally prefer to purchase natural gas during its most liquid period (natural gas price certainty) over being able to obtain pipeline service during the timely nomination cycle (quantity certainty). It said MISO should work with stakeholders to reduce its market solve times further “to allow market participants to submit bids reflecting increased fuel price certainty.”

MISO has 30 days to submit a new compliance filing.

SPP Change Approved

FERC, meanwhile, accepted Tariff revisions SPP submitted in August that moved the deadline for day-ahead market offers up 90 minutes to 9:30 a.m. CT (ER15-2377).

The RTO will now post day-ahead results at 2 p.m. CT, up from 4 p.m., and shorten the reoffer period to 45 minutes, with reliability unit commitment (RUC) offers due at 2:45 p.m. CT and results posted by 5:15 p.m. (See “Board Approves Gas-Electric Timeline Change” in SPP BoD/Members Committee Briefs.)

FERC said SPP had “identified characteristics on its system that justify its proposal not to publish its day-ahead market results prior to the timely nomination cycle,” noting its low risk of natural gas pipeline constraints and the impact changes would have on weather forecasting for its “extensive wind resources.”

The commission ordered SPP to submit an annual informational report for the next three years on its efforts to further align its gas and electric scheduling practices. SPP staff have said they can implement the changes — which will require new software — by next fall. The work is being done in conjunction with an enhanced combined-cycle project, at an estimated combined cost of $7.7 million. (See “Enhanced Combined-Cycle Project Moves Forward” in Board of Directors/Members Committee Briefs.)

No Change for CAISO

The commission also said CAISO had shown good cause why its existing day-ahead practices should not be changed (EL14-22).

CAISO’s July compliance filing said its load-serving entities feared less accurate supply forecasts with an earlier start to the day-ahead market. FERC agreed, saying “moving the close of the day-ahead market earlier could reduce the accuracy of demand, hydroelectric supply and variable energy resource output forecasts.”

The ISO’s day-ahead market closes at 10 a.m. PT and market results are published at 1 p.m. PT.

As with SPP, the commission ordered annual informational reports on CAISO’s efforts to improve coordination of gas and electric schedules.

December 22, 2015

Appeals Court Upholds FERC on West Coast Energy Crisis Case

By Rich Heidorn Jr.

The 9th Circuit Court of Appeals last week sided with FERC in the latest chapter of the long-running legal dispute over the California-West Coast energy crisis of 2000-2001.

A three-judge panel declined to overturn FERC’s decision to apply the Mobile-Sierra doctrine — which presumes that the rate set in a freely negotiated wholesale-energy contract is just and reasonable — in determining whether Pacific Northwest power buyers are entitled to refunds.

The judges also dismissed a challenge to the scope of evidence FERC considered in the Mobile-Sierra review, saying the issue was not ripe for its review.

California Deregulation

The case before the 9th Circuit stems from the turmoil that followed California’s deregulation of the electricity market in the mid-1990s, which resulted in skyrocketing spot prices in California and the Pacific Northwest, largely driven by market manipulation by Enron and other power marketers.

The petitioners, which include the city of Seattle, challenged several FERC orders issued following the 9th Circuit’s 2007 remand of the Port of Seattle case. In that case, the court reviewed challenges to FERC’s denial of refunds to wholesale buyers that purchased power in the Pacific Northwest spot market at unusually high prices.

The court ruled that FERC’s failure to consider evidence of market manipulation was arbitrary and capricious. FERC had to “consider the possibility that the Pacific Northwest spot market was not … functional and competitive,” the court ruled.

FERC was ordered to examine evidence of market manipulation “in detail and account for it in any future orders regarding the award or denial of refunds in the Pacific Northwest proceeding.”

In response, FERC said it would invoke the Mobile-Sierra doctrine, meaning the presumption that the contracts were just and reasonable could be overcome only if specific criteria were met, such as “where it can be shown that one party to a contract engaged in such extensive unlawful market manipulation as to alter the playing field for contract negotiations.”

FERC’s invocation of the Mobile-Sierra presumption meant electricity buyers would need to “demonstrate that a particular seller engaged in unlawful market activity in the spot market and that such unlawful activity directly affected the particular contract or contracts to which the seller was a party.”

FERC said it would not consider “general allegations of market dysfunction” because the Pacific Northwest spot market operated solely through bilateral contracts, unlike the California spot market, which used a central clearing price and a centralized power exchange.

In last week’s order, the court rejected FERC’s contention that it lacked jurisdiction to review the commission’s application of Mobile-Sierra. But it deferred to what it called “FERC’s reasonable determination” that Mobile-Sierra applies to short-term sales.

“The mere short-term nature of these spot sale contracts does not render FERC’s application of the Mobile-Sierra doctrine unreasonable,” the court said. “Although long-term contracts may play a special role in stabilizing the energy market … the Supreme Court has drawn the rule so that the presumption may be invoked with regard to any contracted for rate.”

Evidentiary Challenges not Ripe

The court said, however, that it lacked jurisdiction to rule on the petitioners’ challenges to restrictions that FERC imposed on the evidentiary proceeding. The petitioners said they should be permitted to introduce evidence of reporting violations, violations of obligations under the Uniform Commercial Code and state contract law, and violations by sellers that were not parties to the challenged contracts.

The court said the evidentiary orders are preliminary and lack the “definitive substantive impact” required for the court to assert jurisdiction.

It noted that “FERC has already shifted course on the ‘shape’ of the proceeding in a way that suggests some elements of its orders may not be sufficiently final for review. … Significantly, it appears that despite arguments raised by the petitioners, at least some evidence of bad faith may have been admitted in the [evidentiary] proceeding.”

The court said FERC’s final order resulting from the remand hearing will be reviewable and will allow a “more effective review of the evidentiary decisions since the court will be able to review all of the evidence taken together.”

December 22, 2015

ISO-NE Planning Advisory Committee Briefs

WESTBOROUGH, Mass. — Increasing the export limits at a substation in eastern Maine’s wind country could save millions in power costs and reduce emissions, according to a draft report presented to the ISO-NE Planning Advisory Committee last week.

The study was requested by SunEdison, owner of two wind farms totaling 147 MW, Stetson and Rollins, that are served by the Keene Road substation.

The area around the substation has a peak load of 38 MW, which has dropped in recent years because of the closure of nearby paper mills.

The study found that increasing the export limit from the current 175 MW to 225 MW could save $1.4 million to $5.7 million in production costs annually by allowing additional wind development in the area and displacing more expensive hydropower. The savings are based on production costs of $0/MWh for wind, $5/MWh for hydro and $10/MWh for thermal energy imported from New Brunswick.

CO₂ emissions reductions could range as high as 35 kilotons with the displacement of fossil fuel-fired generation, the draft says.

“The transmission investment could be worthwhile then, as these market efficiencies could be met,” said John Keene, senior counsel at SunEdison.

ISO-NE spokeswoman Marcia Blomberg said the analysis was an economic study of hypothetical system changes. The RTO has not developed cost estimates for the transmission upgrades that would be required to increase the export limits, she said.

Transmission Assumptions

ISO-NE is proposing changes in the way it makes transmission planning assumptions to reduce subjectivity and better reflect the likelihood of transmission constraints and generator outages.

In a presentation to the PAC, ISO-NE identified potential changes, noting that the current base case assumption that two generators are out of service “may be too pessimistic in some cases, too optimistic in others.”

The proposed changes are in response to a 2013 problem statement by the New England States Committee on Electricity (NESCOE), which said the current planning procedure allowed too much subjectivity in base case development.

“The degree of latitude in the current transmission planning procedure can create inconsistency within the region and between the development plans of various transmission owners,” NESCOE said.

Region-of-Reasonable-Test-Assumptions-(ISO-NE)---content-web — ISO-NE is proposing using cumulative probability — the aggregation of the probabilities of specific conditions — to determine a “region of reasonable test conditions” for future planning studies.The RTO said the change would reduce subjectivity and better reflect the likelihood of transmission constraints and generator outages.

The group proposed the use of statistical parameters to narrow the range of assumptions, which it said could increase the uniformity of transmission planning analyses among utilities and expedite state siting proceedings.

ISO-NE proposes using cumulative probability — the aggregation of the probabilities of specific conditions — to determine a “region of reasonable test conditions.”

Under current practice, disturbances are typically studied at peak load levels in steady-state analysis, which usually results in more pronounced thermal and voltage responses. The RTO uses 100% of the projected 90/10 summer peak load for the New England Control Area.

Going forward, the RTO proposes identifying the load and key resources that can stress transmission constraints and determine the likelihood of exceeding various combinations of load and unavailable generation. “This is similar to the installed capacity requirement, but not exactly the same way load is treated,” said Richard Kowalski, technical director of system planning for ISO-NE.

The RTO said its next steps include identifying the most appropriate weeks of the year and hours of the day to use in setting study periods and how to best model intermittent and distributed resources.

— William Opalka

December 21, 2015

PJM Looking at AEP, FirstEnergy PPAs; Critics Join Forces

By Suzanne Herel and Ted Caddell

PJM said Thursday it will weigh in on the controversial power purchase agreements American Electric Power and FirstEnergy negotiated with the staff of Public Utilities Commission of Ohio.

General Counsel Vince Duane told the Markets and Reliability Committee that PJM will analyze how the PPAs — which essentially re-regulate 6,300 MW of generation — will affect the region’s wholesale electricity market.

Duane said the analysis will be released by spring. “Our hope is that this analysis can help to inform the public debate so that regulators and policymakers understand fully any trade-offs that may arise through the policies they may be considering.”

It’s unclear whether PJM’s report will come in time to influence the Ohio commission’s rulings on whether to accept the settlements. A PUCO administrative judge has ordered hearings on the FirstEnergy settlement beginning Jan. 14. The judge ruled that the settlement raised new issues not covered during a seven-week trial this fall.

The companies have said they expect PUCO to rule in early 2016.

AEP Ohio announced the eight-year power purchase agreement on Dec. 14. FirstEnergy announced a similar eight-year PPA on Dec. 1.

“Our job is not to make policy decisions — or to try to prevent lawmakers and regulators from making choices that advance valid state and local interests, even where such choices might complicate PJM’s functions,” Duane said, reading a statement. “It is our job, however, to express our views on regional reliability and the performance of the wholesale electricity markets in assuring that objective in the least-cost manner. This responsibility includes assessing the potential for state policies to negatively impact this objective and informing policymakers of the trade-offs that can arise from their policy objectives.

“The record in Ohio shows that PJM’s markets have, since their inception, succeeded in providing reliable, competitively priced wholesale electricity. Our markets and regional transmission expansion planning process will ensure that wholesale electricity remains reliable and competitively priced in Ohio,” Duane said.

PJM spokesman Ray Dotter said Tuesday that the analysis will be a “general look at the performance and value of markets” and “not be specifically about Ohio.”

Nevertheless, Duane’s comments appeared to rebut the arguments AEP and FirstEnergy have presented to Ohio regulators — that the PPAs were needed to protect ratepayers from volatile natural gas prices and the reliability risks of plant retirements. Wall Street sees the PPAs as a way to prop up the finances of the companies’ aging, uneconomic generators.

Impact on Customers

AEP’s deal provides guaranteed income for the output of the company’s 2,671-MW ownership share of nine plants, as well as its 423-MW contractual share of Ohio Valley Electric Corp.’s (OVEC) generating fleet, until May 2024.

AEP said the agreement would raise a typical residential customer’s bill by 62 cents per month. but save consumers $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 has predicted that the deal would cost consumers an extra $2 billion.

Many of the companies and associations that denounced the AEP settlement also criticized a similar agreement with FirstEnergy. Dynegy and Talen Energy have threatened to sue over the deals. (See Merchant Generators Lead Opposition to FirstEnergy-Ohio Settlement.)

Dynegy is among the members of the newly formed opposition coalition The Alliance for Energy Choice, which enlisted Todd Snitchler, PUCO chairman from 2011 to 2013, to represent their cause.

“I see this as a clear retreat from competitive markets, and it’s an attempt to re-regulate without changing the law, and I don’t think the commission has the power to do that,” Snitchler told The Columbus Dispatch.

Environmental Impacts

AEP won the support of the Sierra Club — which rejected the FirstEnergy settlement — with a promise to double the state’s wind generation and nearly quintuple its solar capacity. AEP’s agreement also includes a promise to retire or convert some of its coal-fired generators to natural gas. (See AEP Ohio Reaches PPA Settlement with PUCO Staff, Sierra Club.)

While the Sierra Club agreed to support the deal, other environmental groups were not swayed by the utility’s promises.

“This shortsighted settlement is a raw deal for people and their health. It guarantees higher energy bills for families and small businesses, big profits for AEP, and at least eight more years of asthma-inducing, climate-warming, dirty energy for all,” the Ohio Environmental Council said.

Dick Munson, director of Midwest Clean Energy for the Environmental Defense Fund, said in a statement: “AEP and its allies will tout the utility’s commitment to close coal plants 15 years from now with this proposed subsidy, even though economics would force its aging, inefficient coal plants to close much sooner. Ohio regulators should foster a fair energy marketplace and reject AEP’s bailout.”

A spokesman for the Environmental Law and Policy Center said that group also opposes the settlement, but provided no details.

‘Thumbing of the Nose’

Republican state Sen. Bill Seitz, who chairs the Senate Public Utilities Committee, was also upset by the deal, saying it is contrary to last year’s passage of SB 310, which repealed the mandate that utilities purchase half of their renewable energy from sources within Ohio.

“The settlement’s requirement for 900 MW of in-state renewables … is a direct thumbing of the nose to a legislative decision, and things will not go well for PUCO if they continue to defy the will of the General Assembly,” he said.

The deal, he said, “unfairly saddles all ratepayers (whether served by AEP or not) with the additional cost of the renewable energy, in addition to making the [competitive retail electric service] providers less able to compete because their customers will be paying for what may be poor choices and bad, costly deals made by AEP.”

The proposed settlement would require Ohio Power, AEP’s regulated distribution company, to buy the output of its parent’s plants.

FirstEnergy’s proposed deal would have its regulated utilities, Ohio Edison, The Cleveland Electric Illuminating Co. and Toledo Edison, purchase 3,244 MW of power from generation owned by its unregulated FirstEnergy Solutions unit: the Davis-Besse Nuclear Power Station in Oak Harbor, the W.H. Sammis Plant in Stratton and a portion of the output of OVEC units in Gallipolis and Madison, Ind.

In both cases, the PPAs are structured to guarantee the profitability of the generating units, which have been losing in the wholesale market to cheaper, newer natural gas plants.

Plant Sales an Option

AEP acknowledged in January that it was seeking a buyer for its merchant units in Ohio and Indiana, including the units covered by the PPA. The settlement does not prevent AEP from selling the plants, but does require any buyer to honor the PPA’s terms.

“Nothing in this stipulation limits the right of AEP Ohio or its affiliates to sell any PPA unit, provided that any such sale would be made subject to the commitments made in this stipulation,” according to the settlement.

“We have the right to sell those plants, but at this time we have no plans to do so,” AEP Ohio spokeswoman Terri Flora said Thursday.

The settlement indicated AEP is seeking to sell its 423-MW share in the OVEC plants, however.

“AEP Ohio will continue reasonable efforts to explore divestiture of the OVEC assets, but the signatory parties agree that ongoing inclusion of the OVEC PPA in the PPA rider is not dependent upon a successful divestiture of the OVEC asset,” it says.

December 18, 2015

NYPSC Directs NYISO to Seek Tx Bids

By William Opalka

ALBANY, N.Y. — New York regulators on Thursday declared a public policy need for long-proposed transmission upgrades and recommended finalists to make competitive bids to NYISO (13-T-0454).

The New York Public Service Commission advanced its AC Transmission proceeding by adopting staff recommendations to select two main projects from 22 proposals for new 345-kV transmission crossing the Central East and UPNY/SENY interfaces: the upgrade of the 91-mile, double-circuit 230-kV Edic-New Scotland-Rotterdam line to 345 kV and the upgrade of the 51-mile, double-circuit 115-kV Knickerbocker-Pleasant Valley line to a 115/345-kV double circuit. (See NYPSC Staff Recommends $1.2B in Transmission Projects.)

NYISO will review transmission and other solutions to address the public policy need identified by the commission, which said persistent transmission congestion causes higher prices and raised reliability concerns.

The declaration will allow the winning developers to obtain cost recovery from the beneficiaries of the upgrades under NYISO’s Tariff. FERC Order 1000 requires transmission providers to consider transmission needs driven by public policy requirements established by state or federal laws or regulations.

The commission asked NextEra Energy Transmission New York, North America Transmission and a coalition of utilities known as the New York Transmission Owners to submit their projects for consideration by the ISO.

The commission’s vote was a victory for Gov. Andrew Cuomo, who proposed an “Energy Highway” to eliminate bottlenecks preventing the delivery of upstate power to load in and around New York City.

Although the ISO will consider non-transmission alternatives, the commission rejected the arguments of the Hudson Valley Smart Energy Coalition and others who insist system reliability could be maintained by increased energy efficiency if even a small percentage of proposed downstate power plants are built.

“There’s no question we need transmission to move power from upstate to downstate, just to maintain basic reliability,” commission Chair Audrey Zibelman said at the meeting.

Later, she said the projects would benefit older, struggling upstate plants. “It makes no economic sense to have plants sit idle when we could have them operating to serve needs downstate,” she said.

Using Existing Rights of Way

The selected projects will be built within existing transmission corridors, with new substations at several points. The PSC said the lines were reaching the end of their useful lives and would need to be replaced in any case.

The upgraded lines will use towers of up to 105 feet to meet NERC standards. The current, lower voltage lines are generally 80 to 85 feet high.

The projects have an estimated cost of $1.2 billion. Officials said a “conservative” cost-benefit analysis by The Brattle Group showed at least $1.20 in benefits for every $1 spent.

“There’s some analysis that the savings from the recommendations could reach $2,” Zibelman said. The savings primarily come from the reduction in congestion charges on those parts of the New York system that are projected to hit $473 million in 2019, rising to $562 million in 2024, without the upgrades. The gap could be even higher if natural gas prices rise from their current low levels.

Raj Addepalli, managing director of utility rates and service for the PSC, presented what he called an “optimistic” timeline under which NYISO could complete its solicitation and analysis of proposals by the second quarter of 2016.

The commission will have to approve the ISO’s recommendations and grant siting certificates for the selected projects. Final commission approval could come in 2017, followed by a two- to three-year construction schedule, with an in-service date of 2019.

NYISO CEO Bradley Jones issued a statement saying the move is an important step in remedying the state’s aging infrastructure. “The NYISO stands ready to solicit projects and will conduct the planning studies necessary to select the most efficient and cost-effective projects that will meet the public policy needs identified by the commission,” he said.

Lifeline for Nukes?

After the meeting, Linda DeStefano of Syracuse, representing the Alliance for a Green Economy, objected that the transmission projects could provide a lifeline to nuclear plants on Lake Ontario. “We think that Gov. Cuomo is very concerned about Indian Point, but we wanted to make the point that we think that the nuclear plants near us are also very old and not safe,” she said.

Phil Wilcox, who observed the meeting on behalf of the International Brotherhood of Electrical Workers Local 97, based in Buffalo, had a different take. “This will give [the nuclear plants] a signal that they may have a future,” he said. Unions have been vocal in support of keeping struggling nuclear plants operating.

No Conflict with REV

The commissioners rejected complaints that the projects would conflict with the state’s Reforming the Energy Vision initiative, a plan to increase the use of distributed and renewable energy.

“The future envisioned by REV is that distributed energy resources deployed locally will help customers become efficient and dynamic electric users. These new customer resources will also be able to be used to more effectively balance increased investments in wind and solar resources that are deployed remotely,” the commission said.

“Additionally, the commission recognizes that large scale central generation, including our safe upstate nuclear facilities that are in their licensed periods, can continue to be operated and new investments can be made to compliment [sic] the distributed resources. Stated another way, while there is no doubt that we can all become better environmental and economic stewards by becoming more efficient energy consumers and using energy more efficiently, the commission also recognizes that in its entirety the optimal system design will be met by a balance of central station and distributed resources and that this balance will be found by markets that accurately value resources and public policies that stress the importance of building an electric system that reduces waste and decreases rather than increases reliance on fossil fuels.”

Projects Selected

Below is a more detailed description of the projects identified by the New York Public Service Commission as the transmission needs driven by public policy requirements:

Segment A: Construction of a new 345-kV line from Edic or Marcy to New Scotland; construction of two new 345-kV lines or two new 230-kV lines from Princetown to Rotterdam and decommissioning of two 230-kV lines from Edic to Rotterdam.
Segment B: A new double circuit 345 kV/115-kV line from Knickerbocker to Churchtown; a new double circuit 345-kV/115-kV line or triple circuit 345-kV/115-kV/115-kV line from Churchtown to Pleasant Valley; decommissioning of a double circuit 115-kV line from Knickerbocker to Churchtown; decommissioning of one or two double-circuit 115-kV lines from Knickerbocker to Pleasant Valley. The commission ordered Orange and Rockland Utilities, the owner of the Shoemaker-Sugarloaf facilities, and Central Hudson Gas & Electric, the owner of the Rock Tavern substation, to cooperate with the developer selected for Segment B.
Upgrades to the Rock Tavern substation: New line traps, relays and other upgrades needed to accommodate higher line currents resulting from the new Edic/Marcy-New Scotland, Princetown-Rotterdam and Knickerbocker-Pleasant Valley lines.
Shoemaker to Sugarloaf: A new double circuit 138-kV line from Shoemaker to Sugarloaf; decommissioning of a double circuit 69-kV line from Shoemaker to Sugarloaf.

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