WASHINGTON — With low oil and gas prices crimping the petroleum industry’s budgets, two major energy lobbying groups are combining forces. The American Petroleum Institute and America’s Natural Gas Alliance will begin 2016 as a single organization under the API banner.
The move appears to be driven by a desire by members of ANGA — a smaller, newer organization — to trim costs. Seven of the 17 members listed on ANGA’s website are also API members.
API, founded about 85 years ago, has more than 625 members, including refiners, suppliers and pipeline operators. In 2013, according to its IRS filings, it had a staff of about 300 and a $49 million payroll, one-fifth of its $238 million budget.
ANGA, founded in 2009, has a staff of about 22 representing 17 dozen independent natural gas exploration and production companies. It reported $7.2 million in payroll in its $67 million budget for 2013.
Ominously, ANGA’s biggest source of income, program service revenue — dues — dropped by more than a quarter in 2013, from $76.7 million in 2012 to $56.5 million in 2013. API’s program service revenue dropped from $225 million to $210 million over the same period.
ANGA ran an operating deficit of more than $10 million in 2013, following a shortfall of $7 million in 2012 — this after running a surplus of $53 million as recently as 2010.
Data for 2014 is not yet available.
Jack Gerard (Source: API)
“As a single organization, the combined skills and capabilities bring an enhanced advocacy strength to natural gas market development,” API CEO Jack Gerard, who will remain in his position, said in a statement. “The combined association’s expanded membership will provide additional lift to API’s ongoing efforts on important public policy issues.”
ANGA president Marty Durbin will lead a new group at API that will handle the gas lobby’s interests. ANGA members not already affiliated with API will become full members.
The organizations did not return requests for comment on whether the merger would result in layoffs. In an email to “colleagues” Tuesday, Durbin named four ANGA staffers he said would be joining him in the transition, promising they would provide “a continued high level of engagement and expertise.”
Gerard earned $14.1 million in 2013. Durbin earned $767,000 after becoming CEO in May of that year.
According to The Hill, API spent $9 million lobbying Congress last year — more than any other energy trade group — while ANGA spent $1.4 million.
Congress’ approval last week of a repeal of the decades-long ban on crude oil exports gave API a rare chance to celebrate lately. It said the legislation “will help bring U.S. energy policy into the 21st century.”
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.
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.”
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.
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.
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.
Vince Duane, PJM General Counsel
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.
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.
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.
All six members of the state’s congressional delegation met on Dec. 10 with U.S. Energy Secretary Ernest Moniz to press for answers about the proposed Plains & Eastern Clean Line transmission project, which would deliver wind energy from the Oklahoma panhandle to Arkansas and Tennessee.
Sens. John Boozman and Tom Cotton earlier this month placed a hold on a presidential nominee for a position at the Energy Department, saying they wanted more thorough answers to their questions about the 700-mile HVDC transmission line. A spokesman for Boozman said Thursday that the Republican senators were unsatisfied with Moniz’s answers and were not ready to lift the stay.
“We continue to have serious concerns that this project erodes the rights of local communities and the state of Arkansas to have a seat at the table in the decision-making process,” the senators said in a statement.
The developers of a proposed 80-MW wind farm haven’t taken some fundamental steps to connect to the region’s grid, utility representatives said last week.
Dragonfly Industries International, which for the past year has pushed to build a wind power facility in Elm Springs, has had only fleeting discussions with the nearest electric utilities that are potential buyers of the power, Arkansas Electric Cooperative Corp. and Southwestern Electric Power Co. “We talked to them a few times, and what we have done primarily is direct them to the Southwest Power Pool,” said SWEPCO’s Peter Main.
But Dragonfly also has not applied to SPP, an essential step to make sure the region’s grid can accept whatever power the wind plant might generate.
Peoples Gas Files New, Lower Estimate on Pipe Replacement
Peoples Gas has reduced the estimated price of its proposed Chicago gas main replacement project in a new filing with the Commerce Commission that pegs the cost at $6.8 billion instead of the $8 billion it earlier reported. The new price, however, is still more than double the original $2.6 billion.
The utility, which said the lower price was possible because of cost controls, is the target of an ICC investigation to determine whether the utility’s owners concealed the project’s escalating price tag before regulators approved the recent merger between Wisconsin Energy Corp. and Integrys Energy Services, the parent company of Peoples Gas.
The new estimate failed to win over Attorney General Lisa Madigan, who has threatened an investigation as well. “Peoples’ report is simply more of the same,” she said. “It does not address concerns we and the independent auditor raised. Instead of a complete overhaul of the program, they’ve decided to forge ahead with little regard for the consumers who are on the hook for this massive cost overrun.”
The Commerce Commission last week approved new delivery rates for Ameren’s electric and gas customers. A typical monthly electric bill will increase in January by $2 to $7, while gas bills will increase $2 to $6.
The revenue will help pay for Ameren’s modernization program. The utility expects to spend $67 million on natural gas line infrastructure and $100 million on its electrical grid next year.
The commission also approved a $67 million rate decrease for ComEd that reflects efficiencies from ComEd’s smart grid rollout. That will translate to about $1 in monthly savings on the average residential bill beginning next month.
Duke Energy Indiana has revised its seven-year $1.83 billion plan to revamp the state’s aging electric grid, hoping to avoid a full-blown rate proceeding. Duke’s 800,000-plus electricity customers in the state are expected to pay about 6% more from 2017 to 2022 to pay for the upgrades.
The Utility Regulatory Commission forced the utility to revise its plan after a court rejected the commission’s approval of an infrastructure improvement plan for Northern Indiana Public Service Co. Utilities in the state are able to recover infrastructure investments using a rate mechanism called a tracker, avoiding a costly rate-increase proceeding. The court’s ruling has forced regulators to review its previous approvals of the tracker surcharge.
Duke’s modernization proposal includes features such as energy-efficient transmission lines, smart meters and a “self-healing” smart grid system that can reroute power during storm outages. Duke has estimated that its grid modernization will create or sustain more than 5,000 jobs. The IURC is expected to make a decision by mid-2016.
Gov. Matt Bevin, a Republican, has named a veteran coal-mining executive as the state’s secretary of energy and environment.
Charles G. Snavely, a 35-year industry veteran who most recently was president of eastern U.S. operations for Arch Coal, holds a mining engineering degree from Virginia Tech.
“Charles understands the balance we must maintain between the commonwealth’s need for low-cost, reliable energy and the need for clean water and air for all Kentuckians,” Bevin said.
Portland is considering building a solar energy farm at a capped landfill and installing solar panels on several municipal buildings.
The move would follow in the footsteps of neighboring South Portland, and it would help Mayor Ethan Strimling fulfill a campaign promise to procure 25% of the city’s power from renewable sources in a decade.
A city-backed proposal by ReVision Energy, a New England solar contractor, would install 2,916 solar modules at the city’s old Ocean Avenue landfill and mount photovoltaic panels on the roofs of schools, airport and library facilities.
Three Democratic legislators are proposing to increase the amount of electricity that state utilities must obtain from renewable resources and to spend $40 million on green job training.
The legislation would set a renewable portfolio requirement of 25% by 2020. The current goal is 20% by 2022.
Supporters say the moves would create 2,000 jobs and reduce carbon emissions by the equivalent of 563,000 cars per year at a small cost to ratepayers.
Net-Metering Cap Inaction Threatens Solar Installations
Downing
Solar advocates say the legislature’s failure to raise net-metering caps could stymie several Berkshire solar projects. State Sen. Benjamin Downing, a Democrat, holds out hope that a compromise can be still be reached that would allow solar developers to take advantage of federal tax incentives that expire at the end of 2016.
Customers who qualify for net-metering are currently capped at 4% of peak electrical usage for private installations or 5% for public installations. The caps have been met in towns served by National Grid, but not in towns served by Eversource Energy.
Solar supporters say that several projects are unable to move forward without a guarantee they will be net-metered, meaning they will be paid the full retail price for any power they send out to the grid. In order to take advantage of federal tax credits, projects have to be fully operational before Jan. 1, 2017.
It is becoming more expensive and complicated to get new energy projects approved in the state, business leaders lamented at the 2015 New Hampshire Energy Symposium, hosted by the New Hampshire Business and Industry Association.
“Applicants are not only facing additional administrative and legal hurdles, but significant financial hurdles to do business in New Hampshire as an energy provider,” said Susan Geiger, an energy lawyer with the Concord firm Orr and Reno.
The legislature has devised new rules for the Site Evaluation Committee to evaluate as it considers an unprecedented push for new pipeline and power transmission projects. The nine-member SEC usually has the final say on such projects, even if they receive the necessary federal permits.
Judge Hears Arguments in Farmington-Bloomfield Dispute
A district court judge is considering a motion to dismiss a City of Bloomfield lawsuit alleging breach of contract in connection to the municipality’s attempt to take over part of the electric system that is owned and operated by a neighboring municipality, the City of Farmington.
Bloomfield argues that under a 1960 agreement, in which Farmington acquired its electric system from a private owner, Bloomfield also had the rights to acquire the power system within its city limits.
At a hearing, a Farmington attorney argued that Bloomfield would have had the rights to infrastructure within its boundaries if it had sought to acquire the utility within 14 years of the agreement. But she said Bloomfield’s rights expired in 1974 under the statute of limitations.
New York State Electric and Gas and Rochester Gas & Electric began drone inspections of 36 NYSEG substations in an effort to evaluate the effectiveness of the remote-controlled aircraft.
The utilities, both owned by Iberdrola USA, had previously used helicopters for the inspections. The evaluation of the drone experience is expected to be complete in the coming weeks.
The drones are being flown only in the immediate vicinity of the NYSEG substations and at a maximum altitude of 300 feet. The contractor has also inspected static wires at a substation owned by Central Maine Power, another Iberdrola subsidiary.
The state’s Green Bank has joined a new international network of public entities to facilitate financing for clean energy initiatives.
The Green Bank Network, an alliance of six of the new public clean energy banks, is aimed at accelerating the deployment of more than $40 billion into clean energy projects around the world, according to Gov. Andrew Cuomo. Initial funding is provided by the ClimateWorks Foundation, whose founders include the William and Flora Hewlett Foundation, KR Foundation, the John D. and Catherine T. MacArthur Foundation, the Oak Foundation and the David and Lucile Packard Foundation.
The state’s bank, which was created as part of the Reforming the Energy Vision plan, will be joined in the network by the UK Green Investment Bank, the Connecticut Green Bank, the Green Fund of Japan, Malaysian Green Technology Corp. and Clean Energy Finance Corp. of Australia. The banks appointed the Natural Resources Defense Council and the Coalition for Green Capital to create the network.
NYISO has enhanced its website to offer more user-friendly information for consumers as well as detailed information about the state’s wholesale electricity markets and high-voltage electric grid.
New sections of the website include value metrics that provide ongoing measurements of NYISO’s performance relating to reliability, markets, planning, authoritative information, financial responsibility and customer satisfaction.
The site includes a new real-time view of the fuel mix being used to generate electricity in New York as well as real-time data on the amount of electricity being used by consumers, dynamic price data and information on power flows to and from the grid.
Industrial Customers to Get Power Bill Price Break
The Utilities Commission has approved a special electric discount for industrial power users aimed at stemming the flow of jobs from the state.
The qualifications for companies to apply for the corporate subsidy, known as a “job retention tariff,” won’t be spelled out until Duke Energy proposes a discounted rate and related details, possibly next year. Such a proposal would need to be approved by the commission.
The subsidy is something Duke has been seeking for favored customers for at least four years. For a utility company, the loss of an industrial customer could be equivalent to disconnecting several large neighborhoods and shopping areas.
About 50 people gathered recently in Schefield to argue against the proposed 87-turbine Brady Wind Energy Center in southern Stark County.
“I think we need to let the Stark County commissioners know that there’s a lot more people out there that are against the wind farm than people who are for, or who are going to benefit from it,” said Tom Reichert, who lives south of Dickinson. He said his view will be obstructed if the project is built.
NextEra Energy Resources, which operates six wind farms in the state, did not have a representative at the Dec. 5 meeting. The second phase of its Brady project could include up to 60 turbines.
Suit: Chesapeake Energy Engaged in Deceptive Business Practices
The attorney general is suing Chesapeake Energy following an investigation into the company’s dealings with landowners to secure oil and gas leases.
“These alleged deceptive business practices occurred as part of a rush to lock up acreage in the Marcellus Shale region,” said Attorney General Kathleen Kane.
The suit asks for restitution and civil penalties under the Unfair Trade Practices and Consumer Protection Law.
The Public Utilities Commission has approved a construction permit for the Dakota Access oil pipeline project. The proposed 1,134-mile pipeline would deliver Bakken crude from North Dakota to Illinois. The $3.8 billion project awaits approval from North Dakota, Iowa and Illinois.
The 2-1 vote came with a list of 49 conditions aimed at protecting landowner rights.
“If this pipeline is constructed, it is imperative and non-negotiable that construction and reclamation be conducted in a manner that allows farmers and ranchers impacted by the pipeline to very quickly get back to their business of producing food for the world in a manner uninhibited by the pipeline,” said PUC Chairman Chris Nelson, who added the conditions before the vote.
Chattanooga Wastewater Resources officials want to build a facility to generate electricity from the 300,000 cubic feet of methane produced each day by a sewage treatment plant.
The city’s Department of Public Works says it will apply for a Tennessee Valley Authority grant to cover more than half the cost of the $6.1 million project, which would burn the methane to fuel a steam turbine.
The grant would come from a 2011 settlement between the TVA and EPA committing the authority to reduce pollution in its service area.
The New Hampshire Site Evaluation Committee (SEC) has turned aside protests and deemed the Northern Pass transmission line application complete.
The Dec. 7 decision means the licensing process for the 192-mile line to connect Canadian hydropower with the New England energy market can continue. The committee, which voted 6-0 to accept the application, is expected to rule in about a year.
Project opponents had maintained that the application was incomplete because developers had not shown they had property access along its entire route, especially at its northernmost point. State environmental officials and a group representing independent power producers had raised questions about site access. (See Northern Pass Facing Challenges over Siting.)
But Commissioner Kathryn Bailey told a crowded hearing room that all the state agencies with permitting authority had concluded the application is complete. “I have a ton of questions about the application,” she said, according to a report by New Hampshire Public Radio, “but I’ll start the discussion by saying I think that what they’re required to provide in order for us to proceed is complete.”
In its letter declaring the application complete, the state Department of Resources and Economic Development said that the project will use existing corridors to cross five state forests under the department’s management. However, it cautioned that any “project-related impacts” to properties purchased through the Land Conservation Investment Program would require legislative action.
Also, under the federal Land and Water Conservation Act, any impacts outside of existing utility rights of way in Bear Brook State Park would require substitution of equivalent recreation properties, subject to the approval of the Interior Department.
Northern Pass Transmission, a subsidiary of Eversource Energy, was pleased with the panel’s ruling. “We appreciate the hard work that the SEC and other state agencies have put into reviewing the contents of this lengthy application, and we are eager to begin the next phase of the state permitting process,” it said in a statement.
The owner of the land alongside state highway rights of way that developers want to use said it was disappointed but not surprised. “As members of the SEC acknowledged, certain property rights are in dispute. The question is when and how those property right issues are taken into consideration by the SEC. The answer to that question is still unclear,” the Society for the Protection of New Hampshire Forests said in a statement.
The society also has filed suit in Coos County Superior Court to stop the project.
Eversource hopes to begin construction in 2017 and begin importing power from Hydro-Québec in spring 2019.
NRG Energy asked FERC last week to approve a revised reliability-must-run contract for its Huntley Power Station. The company said that it may only need to continue operating one of the two units at the 380-MW plant in Tonawanda, N.Y., to ensure grid reliability.
The company asked the commission to revise the cost-of-service agreement it filed Oct. 14, when it was anticipated it might need to keep both of its units running for up to four years until National Grid can complete transmission upgrades needed to address voltage issues.
Last week’s filing said only one unit would be required and for as little as four months beyond its scheduled March 1 retirement (ER16-81).
NRG announced in August it would close the coal-fired units outside Buffalo on March 1.
Each of Huntley’s units has a capacity of 190 MW. Under the NRG plan, Unit 67 would close on March 1, and Unit 68 would run for another four months. NRG said NYISO has agreed to this timeline. If the system operator determines a reliability need, it can unilaterally keep the plant in service for up to another three months, or until Sept. 30.
“NRG is ready to engage with the NYISO, National Grid and the [New York Public Service Commission] to establish certainty around a reliability agreement for Huntley as necessary if National Grid’s transmission upgrades are delayed,” NRG spokesman David Gaier said.
Under the proposed agreement, Huntley would be paid about $8 million per month: $3.56 million for one-twelfth of its annual fixed revenue requirement of $42.7 million, plus $4.46 million in monthly adjustments.
NRG said the plant has become uneconomic in NYISO’s energy and capacity markets due to cheap natural gas.
For the 12 months ending July 31, 2015, the plant had a gross margin — total revenues minus variable costs — of only $16.4 million compared with a cost of service of $90.3 million, according to the company. “In fact, the $16.4 million was sufficient to cover a mere 31% of the facility’s fixed operation and maintenance expenses, let alone any other component of the cost of service,” NRG wrote.
In studies released at the end of October, NYISO and National Grid said the plant, along with a second stressed NRG facility in Dunkirk, could be closed on schedule if transmission upgrades were completed on time. (See NYISO: Two NRG Plants Can Close as Scheduled.)
WASHINGTON — Electric industry officials told FERC last week that its proposal for identifying connections between companies and individuals engaged in trading in RTO markets is too broadly written and will create significant reporting burdens.
The commission’s Notice of Proposed Rulemaking (RM15-23) would require RTOs and ISOs to register market participants through common alpha-numeric identifiers, with lists of their “connected entities” and a description of their relationships. FERC said the change would help it unravel complicated market manipulation schemes. (See Are You Two Related? FERC Wants to Know.)
Matthew Picardi, Shell
Speakers at a technical conference last Tuesday called on FERC to narrow its definition of a trader and to increase the 10% ownership threshold for determining whether entities are connected.
“The proposal in its current state is vague, would create burdensome and duplicative filing requirements, and would add material operational and compliance risks for markets participants and others without providing meaningful tangible benefits,” said Matthew J. Picardi, vice president of Shell Energy North America, speaking on behalf of the Electric Power Supply Association.
David Louw, director of the Macquarie Group’s risk management unit, said the rule could reduce participation in the markets, particularly for those “who are price takers and all those for whom the sale of electricity at wholesale is not part of their core business.”
Brandon Johnson, Berkshire Hathaway
Brandon Johnson, an attorney for Berkshire Hathaway Energy’s NV Energy representing the Edison Electric Institute, added: “We don’t think that FERC has adequately justified and explained the need for this rule.”
The proposal would use Legal Entity Identifiers (LEIs), which are already used by the Commodity Futures Trading Commission and Securities and Exchange Commission to track swaps trades. FERC said the new requirements will help the Office of Enforcement police market manipulation by providing a “more complete view of the relationships between market participants and the incentives underlying their trading activities.” The initiative would also help RTO market monitors in probes of cross-market manipulation, FERC said.
‘Control’ Definition Risks False Positives
Picardi complained that the NOPR overreaches by presuming a company has control even under passive ownership or debt financing arrangements and provides no means for participants to rebut the presumption.
“The final rule should recognize the Chinese walls that exist between marketing and trading firms and their transmission company affiliates pursuant to commission rules and the codes of conduct in order to exclude these independently managed entities from the definition of connected entity,” he said. “The connections that are more remote and will pose an unnecessary burden for no benefit include fuel supply and asset management agreements or bidding and scheduling coordination service agreements that do not afford the supplier an opportunity to control the bidding or operation of its generator customer.”
Picardi cited as an example three market participants that each own one-third of a generator. The operating company, responsible for bidding and scheduling the asset into the markets, should be considered a connected entity, he said. “The other passive owners do not have any control over the operation of the plant, so they could not engage in behaviors for the benefit of other positions or entities they hold,” Picardi said.
FERC Response
In a response to some of the most frequent questions on the NOPR, FERC said it proposed the 10% threshold as a way to determine scienter, or knowledge of wrongdoing — a necessary element to proving market manipulation.
Commissioners Cheryl LaFleur (L) and Tony Clark (R)
“It is not necessary to have a controlling interest in an entity to have a motive to favor that entity. A significant financial interest could provide such a reason, even if it did not confer control,” the commission said. “Ten percent is a customary cutoff for this purpose and is used in many affiliate definitions.”
FERC said passive investors were included because it is concerned with benefit to an entity, as well as control over it. “However, we are sensitive to concerns about the burden this might impose, and welcome comments with specific examples to help us assess whether the burden might outweigh the benefits,” it said.
Fuel arrangements, tool sharing arrangements, physical maintenance arrangements and standard power purchase agreements would not be included, it said.
No Safe Harbor
PJM Market Monitor Joe Bowring said that whatever threshold FERC chooses should not be a safe harbor protection against enforcement actions. He cited the example of a company marketing power for multiple generators in which it has no equity.
PJM Market Monitor Joseph Bowring
“We’re actually concerned — not that the 10% threshold is too low — but it’s too high,” Bowring said. “Exact thresholds, I would agree, are difficult to calculate. Exact thresholds are subject to gaming. A company could limit its ownership, if they wanted to game, to 9.9%. There’s no magic about 10% or 11 or 8.”
Bowring also said FERC should give market monitoring units authority to audit connected entity filings to determine their accuracy, as it has proposed for RTOs and ISOs. “We live and breathe with this data. We know it pretty well and I think we could be helpful to you if we had that authority,” he said.
Reporting Logistics
Picardi and Duke Energy’s Matthew Jones said the filings should be with FERC or a single designee rather than to individual RTOs and ISOs.
“Based on our experience with minimum participation requirements pursuant to FERC Order 741, RTOs/ISOs will not be able to standardize the information collection process enough across markets for there to be any benefits for entities that transact in multiple markets,” Picardi said. “The basic requirements were set out by the commission in Order 741, but each RTO/ISO has implemented the order differently, and periodically each makes changes to their respective requirements that must be reviewed and confirmed each year.”
Trader Definition
Jones, managing director of analytics for fuels and system optimization for Duke, also challenged the proposed definition of a trader.
Larry Parkinson, FERC
Duke “views traders as employees who make short-term trades of power. … Duke Energy does not consider individuals who enter offer curves into the RTO/ISO as engaging in trading activities nor considers individuals negotiating long-term power purchase agreements as ‘traders,’” he said.
In its response, FERC said a trader “is the person who makes the decisions, or devises the strategies, for buying and selling physical or financial products [that] are or may be traded in the organized electric markets. It would not include a person who simply ‘pushes the button’ to make a trade, if that person has no control over or input into the decision-making process.”
Jones also said the 15-day deadline for reporting new agreements and changes to existing ones is too short. “It would be a much easier task to align the contract reporting with the [electronic quarterly report]. The same internal processes for managing compliance for EQR reporting could be used for the RTO/ISO reporting.”
Committed Capacity
Duke suggested the rules apply only to market participants that have committed capacity into an RTO or ISO. “Market participants of an RTO/ISO who have generation assets that are committed outside of an RTO/ISO rarely sell specific capacity to the RTO/ISO. The transactions done by these market participants are energy transactions and are normally done at the ‘border’ without a specific resource named,” Jones said.
Comments due Jan. 22
Comments on the NOPR are due Jan. 22.
Commissioners Cheryl LaFleur and Tony Clark attended part of the two-hour session, which was chaired by Director of Enforcement Larry Parkinson.
The commission approved the NOPR unanimously in September, but LaFleur issued a concurring statement saying she might oppose the final rule if she concludes that the reporting burdens outweigh the benefits.
Peoples Gas has reduced the estimated price of its proposed Chicago gas main replacement project in a new filing with the Commerce Commission that pegs the cost at $6.8 billion instead of the $8 billion it earlier reported. The new price, however, is still more than double the original $2.6 billion.
The Commerce Commission last week approved new delivery rates for Ameren’s electric and gas customers. A typical monthly electric bill will increase in January by $2 to $7, while gas bills will increase $2 to $6.
Duke Energy Indiana has revised its seven-year $1.83 billion plan to revamp the state’s aging electric grid, hoping to avoid a full-blown rate proceeding. Duke’s 800,000-plus electricity customers in the state are expected to pay about 6% more from 2017 to 2022 to pay for the upgrades.
It is becoming more expensive and complicated to get new energy projects approved in the state, business leaders lamented at the 2015 New Hampshire Energy Symposium, hosted by the New Hampshire Business and Industry Association.
The state’s Green Bank has joined a new international network of public entities to facilitate financing for clean energy initiatives.
About 50 people gathered recently in Schefield to argue against the proposed 87-turbine Brady Wind Energy Center in southern Stark County.
The attorney general is suing Chesapeake Energy following an investigation into the company’s dealings with landowners to secure oil and gas leases.
Chattanooga Wastewater Resources officials want to build a facility to generate electricity from the 300,000 cubic feet of methane produced each day by a sewage treatment plant.
Project opponents had maintained that the application was incomplete because developers had not shown they had property access along its entire route, especially at its northernmost point. State environmental officials and a group representing independent power producers had raised questions about site access. (See 
Last week’s filing said only one unit would be required and for as little as four months beyond its scheduled March 1 retirement (
