FERC last week reversed an administrative law judge’s 2013 finding preventing Entergy from including the costs from an abandoned repowering project in the company’s allocation of costs to its operating companies.
Judge Philip Baten in June 2013 rejected efforts by Entergy Services and the Louisiana Public Service Commission (LPSC) to pass on to ratepayers through its “bandwidth formula” $200 million in canceled costs from the $1.8 billion Little Gypsy repowering project (ER12-1384-001, et al).
FERC’s Nov. 20 ruling said Baten’s reading of a provision in Entergy’s system agreement was “unreasonably narrow.” It said adopting his interpretation would negate the inclusion in the bandwidth formula of other production-related costs that were just and reasonable, and found Entergy’s proposal to include Little Gypsy cancellation costs in the bandwidth formula consistent with the system agreement.
Entergy uses its bandwidth formula to allocate production costs among its half dozen operating companies under its system agreement. Payments are made annually by low-cost operating companies to the highest-cost company in the system, using a bandwidth remedy that ensures no operating company has production costs more than 11% above or below the Entergy system average.
FERC also reversed Baten in including the project’s cancellation costs in the bandwidth formula as being “consistent with the purpose of the bandwidth remedy.” It disagreed that the inclusion of the costs “would constitute a landmark policy shift for the Entergy system,” as Baten had said, noting that the commission had already determined the propriety then-current version of the system agreement.
The commission disagreed with the initial ruling and interventions by the Arkansas and Mississippi regulatory commissions, which argued the cancellation costs should be considered “construction work in progress” and excluded from the bandwidth formula. Noting that Entergy had securitized the cancellation costs, FERC found them to be production costs “and, therefore, “the kinds of costs that are appropriate for inclusion in the bandwidth formula.”
At the same time, FERC affirmed Baten’s decision that the repowering project met the needs of the Entergy System “as a whole,” and not just regional needs. It rejected the Mississippi Public Service Commission’s allegation that the LPSC “avoided cost responsibility for its ratepayers” by approving the project’s cancellation, rather than require it be completed.
The commission also sided with the judge in ruling that the LPSC had failed to provide sufficient evidence backing its complaint that his ruling was discriminatory.
The Little Gypsy project would have converted an old gas-fired generator on the Mississippi River west of New Orleans into a petroleum-coke burner. Entergy cited the shale-gas boom and resultant drop in natural gas prices in suspending the project in 2009. It wasn’t until 2011 that the LPSC officially canceled the project and granted cost recovery.
The first call, which was hampered by poor sound quality, focused on the regulatory framework and the CPP’s impact. Several public speakers indicated they had not yet formed a position.
Future calls will discuss the federal plan’s structure, the mass-based implementation approach and the rate-based implementation approach. A face-to-face meeting will be scheduled in early January.
United Illuminating will start work next spring on a microgrid that will allow municipal buildings in the Town of Woodbridge to operate independently of the grid, powered by a 2.2-MW fuel cell.
The centerpiece of the microgrid is a fuel cell that under normal conditions will generate power for the regional electric market. But if the grid fails, the generator will provide power to town hall, the library, the fire station, the police department, the public works department, a senior center and a high school.
The fuel cell, to be owned by UI, will be manufactured by Danbury-based Fuel Cell Energy and will be located on the grounds of Amity Regional High School. Waste heat from the fuel cell will be captured to produce domestic hot water and to heat the school.
Probe: Did Execs Mislead ICC About Ballooning Project Costs?
Madigan
The Commerce Commission will investigate whether executives involved in the $5.7 billion buyout of Peoples Gas failed to disclose the escalating costs of a massive pipe-replacement program during merger proceedings.
The probe grew out of a Sept. 30 auditor’s report that said Peoples Gas executives knew in January, well before they testified before the commission in May, that the estimated cost of replacing 2,000 miles of aging Chicago gas mains had nearly doubled to more than $8 billion.
While the commission dismissed Attorney General Lisa Madigan’s petition asking for a wide-ranging investigation, it will permit her to present other evidence of suspected misrepresentations. The gas utility’s new owner, WEC Energy Group, is expected to propose cost-cutting measures to the ICC this month.
Rock Island Line Stalls as Landowners Turn down Easement Offers
The proposed Rock Island Clean Line that would transmit 3,500 MW of wind power has hit a roadblock after the developer failed to secure easements from a large number of landowners along its route.
Clean Line Energy Partners told the Utilities Board to halt its technical review of the project while the company considers “whether and how to proceed.” Clean Line has secured easements from just 176 of the 1,540 parcels needed for a route that crosses 16 counties, according to the Preservation of Rural Iowa Alliance, an opposition group.
Landowners say delays in the transmission line’s progress has cast a cloud over potential real estate deals and development along the proposed route. A lawmaker says he intends to introduce a bill to establish a deadline for completing the collection of voluntary easements. The bill will also stipulate that a transmission developer cannot exert eminent domain until at least 80-85% of affected landowners voluntarily grant easements.
Construction to Begin on State’s Largest Solar-Powered Site
Construction is expected to begin this month on the state’s largest solar-powered generating facility, according to Louisville Gas & Electric and Kentucky Utilities.
The 10-MW solar farm will consist of about 45,000 photovoltaic panels erected on 50 acres at the E.W. Brown Generating Station, a Mercer County coal and gas plant owned by the two utilities, which are subsidiaries of PPL.
The $36 million facility is expected to generate 19 GWh of energy, enough to power 1,500 homes, when it starts operating in the late spring.
Toyota Plant Supplements Power with Methane from Dump
A Toyota manufacturing plant in Georgetown is tapping into the energy trapped in a landfill to generate power. Toyota officials said the system that captures and burns landfill methane is capable of producing 1 MW currently but can be upgraded to produce 10 MW.
The automaker has installed a generator at the Central Kentucky Landfill that will send power to its plant via a 6-mile transmission line.
There are 645 landfill methane projects operating across the nation with a capacity to produce 2,066 MW, according to the Environmental Protection Agency’s Landfill Methane Outreach Program.
Kentucky Utilities and Louisville Gas & Electric have filed requests to each install 10 new electric vehicle charging stations. Under the filing with the Public Service Commission, the utilities propose that the full cost of charging stations will be borne by those who request the stations or who use the charging service.
More than 15,000 EVs have been registered in the past five years in Kentucky, where there are about 30 public charging stations. The Electric Power Research Institute recently published a report that indicates interest in EVs is growing.
Home and small-business customers of Central Maine Power who buy electricity through the utility’s standard offer will see slightly lower rates in 2016. The Public Utilities Commission has accepted a bid for energy supply that is 3.7% lower than last year’s average, which will translate to savings of $1.35/month on a typical residential bill.
According to the commission, energy supply rates will dip to 6.46 cents/kWh next year from 6.71 cents currently. About 40% of the utility’s customers receive the standard offer rather than buying power from a competitive supplier.
“The standard offer prices set this week reflect the best bids received in a strongly competitive auction process,” said Mark Vannoy, PUC chairman. “We are pleased that prices remain stable or slightly decreasing, allowing retail customers and businesses to benefit from recent downward trends in energy markets that have been reflected in New England wholesale prices.”
The environmental group Food & Water Watch has launched a campaign to force legislators to remove chicken manure as a resource from its renewable portfolio standards.
Poultry farms in the state produce more than 650 million pounds of chicken manure annually. As an incentive to keep the waste out of the Chesapeake Bay, legislators in 2011 added the waste to the RPS, in the same top-tier category as solar and wind.
However, few chicken-manure methane capture projects have materialized, and environmentalists say that burning the manure produces toxic chemicals.
Public Service Commission staff have drafted regulations that would allow residents to subscribe to a community solar energy generation system through a pilot program.
The public may submit comments until Dec. 4. The commission will consider the regulations at its Dec. 14 meeting.
Community solar projects, which may appeal to customers who are unable to install rooftop solar, would be permitted up to 2 MW in size.
House, Senate at Stalemate on Solar Incentives, Caps
Lawmakers failed to complete a deal to update the state’s solar incentives before wrapping up for the year. Leaders appointed a conference committee to hammer out a deal that could delay any agreement at least until formal sessions resume in January.
The sticking point is cost. The House’s proposal would significantly curb the state’s net metering credits once the state hits a target of 1,600 MW, while a Senate bill was considered to be more generous to the solar industry.
The law now caps the amount of net metering credits allowed in a particular utility’s system. Those caps have already been reached in National Grid’s territory for non-residential projects, delaying a number of installations. Both the House and Senate bills would increase the caps.
Clean Line to Appeal for Approval on Grain Belt Express
Clean Line Energy will again try to convince the Public Service Commission to approve the Grain Belt Express transmission line that would carry wind-generated electricity from Kansas through Missouri and Illinois to Indiana.
State regulators, who rejected the a certificate of need for the project in July by a 3-2 vote, are the last remaining hurdle for the $2 billion 780-mile transmission line, which was recently approved by Illinois utility regulators. A certificate of need would allow Clean Line to acquire property through eminent domain.
Landowners who oppose the line are also seeking to block the project.
Group Tries Using Farming Law to Stop Mark Twain Tx Line
Opponents of Ameren’s proposed 100-mile Mark Twain transmission line are challenging the project on the grounds that it would allegedly violate the state’s recently enacted “right-to-farm” amendment. The line would deliver wind power from the Iowa border to the grid, according to Ameren.
The group, called Neighbors United Against Ameren’s Power Line, contends that the project would “permanently remove citizens’ property from production and prevent these citizen farmers and ranchers from engaging in farming and/or ranching practices.”
The Public Service Commission rejected the group’s motion to dismiss Ameren’s application for a certificate of necessity, but it said the amendment could still potentially be used in a court challenge. Ameren told the commission that the argument advanced by the activists is “patently absurd” because it would potentially outlaw “every single new electric line, gas line, water line, sewer line” that would “take any farm land whatsoever out of production.”
New Jersey Natural Gas has asked the Board of Public Utilities to increase rates by $148 million, which it says it needs to upgrade its infrastructure.
The increase would boost a typical customer’s bill by about 24%, or about $236 more a year.
The utility says that wholesale natural gas prices are dropping, so it needs to increase delivery rates to make up the difference in revenue. The rate-increase request is the company’s first since 2007.
Two wind farms being built for $430 million are nearing completion. Construction was delayed because of excessive winds.
Contractor Cielo Wind Power, which manages the projects, said the wind created some problems in the last two months for construction crews, but employees have been able to make up for most of the setbacks by working weekends and other off days.
The Roosevelt Wind Project’s 125 turbines are already energized. The Milo Wind Project, which includes 25 wind turbines, is not yet operating. Roosevelt’s 250 MW is committed to Xcel Energy and Milo’s 50 MW of energy will be sold on SPP’s open market.
The Cuomo administration is urging the U.S. Nuclear Regulatory Commission to deny Entergy’s applications to extend the licenses of two reactors at the Indian Point Energy Center.
“Allowing Entergy to operate these facilities for another 20 years puts the lives of too many New Yorkers at risk,” wrote Jim Malatras, director of state operations. He said the plant’s location near New York City “makes it absolutely impossible to have an effective safety and evacuation plan.”
The administrative law judges of the Atomic Safety and Licensing Board are currently hearing testimony on the request.
Bald Eagles Given Consideration in Wind Farm Development
The Public Service Commission has approved a 100-MW, 59-turbine wind farm on 15,000 acres near the Canadian border. The $175 million project’s developer, Rolette Power Development, agreed to several concessions to minimize the wind farm’s impact on bald eagles.
The U.S. Fish and Wildlife Service determined that there were no eagle nests in the project area, but it did find nests nearby. Rolette amended its application “to allow for various stipulations to minimize impact on the birds.” The company pledged to remove dead livestock and roadkill from the site so as not to attract eagles.
The University of Pittsburgh has received a $2.5 million grant to research ways to shift the grid from alternating current technology to direct current, reviving the 19th Century “War of Currents” between George Westinghouse and Thomas Edison over which type of power transmission would dominate.
“Very few items today require three-phase alternating current,” said researcher Greg Reed, who founded and runs the university’s Direct Current Architecture for Modern Power Systems program.
“The use and development of today’s evolving energy mix, which includes more DC resources such as solar photovoltaics, as well as electric vehicles and battery storage systems, also makes transition to DC more sensible and viable for future power-delivery needs.”
The Public Utilities Commission does not consider many new wind projects, as a state law exempts wind farms that produce less than 100 MW from having to get a permit.
So the PUC on Nov. 12 had the rare opportunity to approve the 103-MW Willow Creek wind farm. It was the first wind project for the two newest commissioners, Chris Nelson and Kristie Fiegen. They joined the remaining commissioner, long-time member Gary Hanson, in approving the proposal by Colorado-based Wind Quarry.
Wind Quarry intends to erect 45 turbines, each 440-feet tall, across three townships in Butte County. The project would connect with a Western Area Power Administration transmission line.
Old Dominion Electric Cooperative selected Hecate Energy to build two solar projects in Northampton and Clarke counties.
The Cherrydale project, in Northampton, is expected to deliver about 20 MW. The Clarke County project will produce about 10 MW. They are expected to be in service by the end of 2016.
Leesburg entrepreneur Karen Schaufeld is developing what is thought to be the state’s largest privately funded solar array on her 63-acre farm in an effort to create a community-based grid.
She wants to develop a model of solar power that is less expensive and more efficient than the power offered by Dominion.
The practice is called Agriculture Net Metering, and Schaufeld’s project is expected to generate more than 450 kW.
Dominion Resources said last week it plans to invest $11.7 billion over the next six years in capital projects, including new generating plants, transmission lines, a gas pipeline and environmental cleanup.
About half the spending is targeted for the state, where the projects are expected to make an economic impact of $1.68 billion annually.
Only one project on the list, a gas-fired generator in Brunswick County, has been approved. Others are at various stages of development.
PSC Considers WPS Hike Request, Cuts Rates for Electric and Gas Instead
Wisconsin Public Service may regret the day it filed a request with the Public Service Commission to raise electric rates by 9.7% and natural gas rates by 2.7%.
On Thursday the commission voted to cut the utility’s electric rates by 0.7% and to reduce gas prices by almost 2%. An average residential electric bill will decrease from $80.93 to $80.80, and the typical gas bill will drop from $53.93 to $52.84.
The commission did approve a $2 increase in the utility’s fixed monthly charge for electric customers, bringing it to $21 from $19. WPS had asked the customer charge to be set at $25.
FERC said last week that three Berkshire Hathaway Energy utilities that plan to join CAISO’s energy imbalance market (EIM) failed to demonstrate a lack of market power.
The order — one of four the commission issued regarding the ISO’s expansion plans — said market power analyses by PacifiCorp and NV Energy’s Nevada Power and Sierra Pacific Power were deficient (ER15-2281, et al.).
The order also noted the commission’s concerns regarding the ability of CAISO to mitigate the companies’ market power. It said the Berkshire Hathaway companies must offer units participating in the EIM at or below each unit’s default energy bid. It also required the companies to cooperate with CAISO’s enforcement of internal transmission constraints in the PacifiCorp and NV Energy balancing authority areas.
The commission also granted CAISO’s request to include in its local market power mitigation procedures transfer constraints between the NV Energy balancing authority area and the CAISO and PacifiCorp East balancing authority areas (ER15-2272).
A third order approved CAISO’s proposed readiness requirements for entities joining the EIM (ER15-861-004). The order also accepts CAISO’s proposed thresholds for measuring the entity’s readiness and its process for granting exceptions to the thresholds.
Another order accepted the ISO’s proposal regarding modeling unscheduled flows and enforcement of physical flow limits on its interties (ER14-2017-001).
Justice Department, EFH Settle on NM Uranium Mines
The Justice Department has reached a settlement with Energy Future Holdings over claims the company’s bankruptcy could leave taxpayers on the hook for millions of dollars to clean up long-shuttered uranium mines in northwest New Mexico that one of its subsidiaries inherited.
An attorney for EFH, which primarily owns utilities and power generation assets, announced a “settlement in principal” in U.S. Bankruptcy Court in Wilmington, Del., on Nov. 19.
EPA Settles with Pa., W.Va. Natural Gas Processing Plant Operators
Elkhorn Investments and Elkhorn Gas Processing will pay a $50,221 penalty under a settlement with the Environmental Protection Agency for alleged violations at five natural gas processing plants in Pennsylvania and another in West Virginia.
The plants, in McKean, Warren and Putnam counties, have come into compliance with risk management and safety requirements, EPA said. The violations occurred under two separate sections of the Clean Air Act.
Entergy officially notified the Nuclear Regulatory Commission that it intends to close the James A. FitzPatrick Nuclear Power Plant in New York by early 2017 “due to the current continued deteriorating economics of the facility.”
New York officials had held out hope that they could convince Entergy to keep the plant on Lake Ontario open, even after Entergy made a public announcement that it intended to shut it down. (See Entergy Closing FitzPatrick Nuclear Plant in New York). Entergy, in keeping with a requirement to notify NRC promptly of any decisions, told the agency that it does, indeed, intend to shut down the plant near Oswego.
“Entergy and state officials worked very hard over the past two months to reach a constructive and mutually beneficial agreement to avoid a shutdown, but were unsuccessful,” said Entergy spokeswoman Tammy Holden.
Sens. Against EPA Rules Got Big Contributions from Coal
Manchin
The 52 U.S. senators who voted last week to scrap two controversial Environmental Protection Agency regulations that would affect coal interests accepted an average of $75,802 in campaign contributions from coal interest groups, according to a CNBC review of public records.
Senate Majority Leader Mitch McConnell, a Kentucky Republican, accepted $350,000 in campaign contributions since 2009. Sen. Joe Manchin of West Virginia, another state where coal is king, has accepted nearly $500,000 from coal groups since 2009.
Manchin is unapologetic. “The president’s energy agenda has had a crushing impact on West Virginia and other energy states,” he said in a statement released last week.
DOE Awards $800K to Penn State to Study Nuke Waste
The Energy Department is sending $800,000 to Pennsylvania State University researchers who are trying to find ways to isolate and strip cesium and strontium from nuclear waste, according to Hojong Kim, assistant professor of materials science and engineering at the university.
“Alkali and alkaline-earth elements are very strong and reactive metals, so it is hard to separate them from other elements,” Kim said. “Cesium and strontium have a relatively short half-life — about 30 years — so they produce the highest amount of heat in the short term of all radioactive elements created through nuclear fission.”
A group of House Democrats is investigating whether oil and coal companies have lied to the public about climate change.
The lawmakers said they were prompted to action by recent news reports that Exxon Mobil knew as early as the 1970s that oil and natural gas cause global warming but later emphasized doubt about the science. The lawmakers want to see if other companies have a similar history.
Reps. Ted Lieu (D-Calif.) and Peter Welch (D-Vt.) are asking colleagues to sign letters that will be sent to Chevron, Exxon Mobil, ConocoPhillips, BP, Royal Dutch Shell and Peabody Energy to ask what the companies knew about global warming and when they knew it.
Exelon’s Byron Nuclear Station Renewal Application OK’d by NRC
The Nuclear Regulatory Commission has approved Exelon’s request for 20-year extensions to the operating licenses of the two units at Byron Generating Station in Illinois.
Exelon, however, said it has not made a final decision on whether or not it will continue to operate the economically challenged plants for another five years, let alone 20. The energy giant has said that Byron is losing money, and without government incentives it may be forced to shutter the plant.
It said a decision on the plant’s future has been deferred for at least another year.
NRC Issues EIS for Possible Fourth Reactor at Artificial Island
The Nuclear Regulatory Commission issued the environmental impact statement on a possible fourth reactor to be built on the grounds of Public Service Enterprise Group’s Salem and Hope Creek nuclear stations.
NRC found no major environmental barriers to building a reactor on the site, where three nuclear reactors currently operate. PSEG submitted the EIS in 2010 for a possible new nuclear plant but says it has no immediate plans to go forward with the project.
“We don’t have any plans right now with the economics [being what they are],’’ said Joseph Delmar, a spokesman for PSEG Nuclear, which operates Salem I and II and Hope Creek reactors on Artificial Island in the Delaware Bay. “It doesn’t make sense.”
WILMINGTON, Del. — The Markets and Reliability Committee last week delayed a vote on proposed manual changes over concerns that they could restrict energy efficiency participation in the capacity market. Members requested an additional education session on the issue.
The revisions aim to prevent EE resources from being counted both as capacity resources and as reductions in the load forecast. PJM proposes to use an add-back mechanism to accommodate continued EE participation when a new load forecast model is adopted.
Energy efficiency resources may be used to replace the commitment of a similar resource because such commitments would have been accounted for by the add-back. However, when it comes to using EE resources to replace non-EE capacity resources, they would be limited to the difference between the add-back of the third incremental auction for a delivery year and the cleared quantity of energy efficiency resources in that same auction.
“The concern is that the add-back might be greater than what might clear,” said Jeff Bastian, manager of capacity market operations.
Several members expressed concern that the eligibility requirements outlined in the changes restrict the time periods that EE resources may offer.
“I have an issue regarding the eligibility and the way EE is treated as a capacity resource. It becomes ineligible in the same year that it cleared in the [Base Residual Auction],” said Carl Johnson, representing the PJM Public Power Coalition. “I struggle to think of a resource that is ineligible depending on when it is offered in.”
“The resource is unique in that it can get buried in the load forecast,” explained Stu Bresler, PJM senior vice president for markets. “We’re doing everything we can to preserve EE as [a Reliability Pricing Model] option. The other option is to not include it in the auction.”
Bruce Campbell of EnergyConnect said he opposed the changes.
“I think it’s a really dangerous path to go down to say we’re not going to let resources participate as RPM resources because it will make our forecast look bad,” he said. “That’s just wrong.”
Responded Bresler: “The bottom line is if we don’t include it in the load forecast three years ahead, we miss the chance, and it’s been rolled in by the time that year comes around.”
The educational session on the revisions proposed for Manual 18: PJM Capacity Market and Manual 18B: Energy Efficiency Measurement & Verification is tentatively scheduled for Dec. 9.
Members Approve Manual Changes
Members endorsed the following manual changes:
Manual 01: Control Center and Data Exchange Requirements. Adds requirements and changes terminology to be consistent with North American Electric Reliability Corp. standards. Adds two communications requirements: voice communications between transmission owners and distribution providers in the transmission owner area, and between transmission owners and generator operators. Adds term “interpersonal communication” for voice communication. Identifies satellite telephones as preferred method of communication. New section requires that communication failures lasting 30 or more minutes be reported within 60 minutes of detection. Makes minor edits for clarity. Removes dated reference to “floppy disk.”
Manual 03: Transmission Operations. Changes resulting from bi-annual review include project updates, edits and reorganization of sections. Updates generator voltage schedule to define coordination. Changes will be implemented Dec. 1.
Manual 12: Balancing Operations. Updates due to new instantaneous reserve check implementation. Eliminates mention of MISO as the interconnection time monitor. Replaces the term “supplemental reserve” with “secondary reserve.” Changes will be implemented Dec. 1.
Manual 13: Emergency Operations. Updates day-ahead scheduling reserve requirement to 5.7% from 5.93% for Reliability First Corp. effective Jan. 1. Other changes made for consistency. Removes requirement that generators connected below 230 kV participate in voltage reduction.
Manual 14B: PJM Regional Transmission Planning Process. Changes reflect new process of considering energy market uplift in development of the Regional Transmission Expansion Plan.
New Load Forecast Model, Related Manual Changes Adopted
With three abstentions, members endorsed revisions to Manual 19: Load Forecasting and Analysis to reflect updates to the PJM load forecast model.
The changes add variables to account for trends in equipment and appliance saturation and energy efficiency; revise weather variables; update weather station assignment to zones; and revise the weather normalization procedure.
PJM will be publishing a white paper in 2016 to provide more detail on the forecast model.
PJM’s Tom Falin said the impact of the change in solar generation is being quantified, and the committee will be asked to endorse related manual changes in December.
Subcommittee’s Proposed Changes to Governing Documents OK’d
The committee endorsed modifications, clarifications and revisions to 12 terms in PJM governing documents.
The developers of the Northern Pass transmission line may have to fight in court before they turn the first shovel of dirt on their project to deliver Canadian hydropower to the New England grid.
The Society for the Protection of New Hampshire Forests on Thursday sued Northern Pass Transmission to prevent it from using land the society owns. The lawsuit says Northern Pass does not have the legal right to access Forest Society lands and should be permanently barred from using it.
The suit came three days after New Hampshire environmental officials said that the developers’ siting application is incomplete because they had not shown they have property rights along the entire 192-mile route.
The letter from the state Department of Environmental Services to the New Hampshire Site Evaluation Committee said the application lacks “proof that the applicant will have a legal right to undertake the project on the property if a permit is issued.” The department was asked to weigh in on the application due to the project’s “alteration of terrain” and wetlands disturbances.
Northern Pass filed the siting application last month, starting a process that is expected to take 14 months. Developers hope to put the line in service in 2019. (See Northern Pass Files for Siting Approval, Revises Cost.)
In announcing the Forest Society’s lawsuit, President Jane Difley said the group “has a legal and ethical obligation to defend” its land against commercial development.
“Northern Pass cannot show that it has the property rights it would need to build the facility it is looking to permit through the Site Evaluation Committee. Nor does Northern Pass, as a merchant transmission project, have the ability to use any form of eminent domain to acquire those rights,” Difley said in a statement.
The lawsuit asks the Coos County Superior Court for a declaratory judgement that Northern Pass has no right to excavate along Route 3 in land known as the Washburn Family Forest. The land is in an 8-mile section near the Canadian border where the developers have proposed to bury the line. The Forest Society is also seeking intervenor status before the siting committee.
“Northern Pass is a private entity seeking to make use of Forest Society lands for the exclusive use of Hydro-Quebec,” said the group’s attorney, Tom Masland. “It is our strongly held view that they cannot do so without the Forest Society’s permission.”
The society says the project, as a merchant transmission line not deemed necessary by the state Public Utilities Commission, is not entitled to use highway rights of way the same way as other utility infrastructure.
“We are disappointed but not surprised that the Forest Society has today taken legal action to circumvent the N.H. Site Evaluation Committee’s authority,” Northern Pass said in a statement. “We are confident that our [siting committee] application meets the standards outlined in N.H. statutes and SEC rules, and that the Forest Society’s claims to the contrary have no basis in fact or law.”
Northern Pass also said that use of a public road is a legitimate use for projects that would benefit the region by providing access to affordable electricity.
“It is hypocritical that the Forest Society has long argued for additional underground construction but is now challenging our proposal to do just that,” the developers said.
The New England Power Generators Association also raised objections to the project in a letter to the site committee.
It said the relationship between Northern Pass and its parent company Eversource Energy raises “concerns about potential undue preference and a slanted playing-field harming competitive outcomes for the electricity marketplace and consumers. This is particularly true when a competitive energy affiliate may use property, services or receive other benefits provided by utility ratepayers for utility purposes.”
A Northern Pass spokeswoman said it is not uncommon for applicants to be asked for additional information.
“We are confident that any potential issues will be resolved in a timely manner and our application will be deemed complete by the SEC,” Lauren Collins said.
The project is in a 60-day window for the siting committee to determine if the application is complete.
The Environmental Services Department said enough information was provided to begin its technical review while the application’s deficiencies are addressed.
New York utilities last week challenged an order by regulators to temporarily remove the 6% cap on net metered solar-powered systems, saying the move violated state law by failing to provide adequate notice and that the regulators did not adequately justify that the move was in the “public interest” (15-E-0407).
The utilities asked for rehearing of the New York Public Service Commission’s Oct. 16 order that removed caps statewide while the commission develops a long-term solution to determine the value of distributed solar. (See Net Metering Caps Temporarily Lifted in NY.)
“The order contravened the statutory requirement that limits the commission’s role to increasing the ‘percent limits’ of the net metering cap, not removing them,” the petition alleges.
One of the six distribution utilities, Orange and Rockland Utilities, said in the summer that it was close to reaching its limit of 6% of load for net-metered systems.
The PSC responded with an administrative notice in the New York State Register on Aug. 5 seeking comments on the O&R petition. “The commission … may extend relief, in whole or in part or as modified or related, to other electric utilities,” the notice said, naming the other five.
The utilities contended last week, however, that “there was no reasonable basis to assume that a request for comments on a compliance filing made by a single utility would be the basis for the commission implementing a new generic policy with respect to net metering, especially considering the manner in which the commission had properly noticed and duly considered its intended action to increase the net metering cap on two prior occasions.”
First raised from 1% to 3% in June 2013, the cap was boosted to 6% in December 2014.
Commissioner Diane Burman dissented from the PSC’s October order, saying the process used to adopt it failed to give adequate notice to the public or other utilities that a sweeping change was under consideration.
The utilities also say that state law authorizing the PSC to raise the cap restricts the commission to impose a “percent limit.”
“Although the commission characterizes its action as a ‘floating’ cap … this nomenclature does not change the fact that the actual and practical import of the order is that there is no cap at all during the interim period and the commission thereby exceeded the statutory constraint,” they wrote.
FERC denied rehearing of three orders related to ISO-NE’s Pay-for-Performance program that is intended to boost reliability starting in 2018. In jump ball proceedings, FERC had said neither ISO-NE’s nor the New England Power Pool’s proposals in themselves addressed performance adequacy, but the commission adopted elements of both.
The first order directed ISO-NE to adopt a modified version of its proposed market design (ER14-1050, EL14-52-001). The commission accepted ISO-NE’s Tariff revisions regarding the increased reserve constraint penalty factors, the treatment of energy efficiency resources and ISO-NE’s proposal to retain the capacity performance payment rate and the dynamic de-list bid threshold.
In the second order, FERC denied rehearing on a commission order regarding an ISO-NE compliance filing (ER14-2419, EL14-52-002). Connecticut and Rhode Island had argued that the order failed to ensure that the dynamic de-list bid threshold is reasonably calibrated in light of the increased reserve constraint penalty factors. The commission said their assumptions are based on an oversimplification of the relationship between the penalty factors, resource performance and the inputs into the dynamic de-list bid threshold formula.
FERC also denied rehearing of a complaint by the New England Power Generators Association that alleged that the interaction between the penalty factor and ISO-NE’s peak energy rent mechanism is unjust and unreasonable (EL15-25). The PER requires suppliers to issue rebates to customers when energy prices exceed a strike price. The penalty factor, a component of the real-time dispatch and pricing algorithm, serves as a cap on the price that ISO-NE may pay to procure additional reserves. The commission found in its earlier order denying the complaint that NEPGA had not met its burden under Section 206 demonstrating that the existing Tariff provisions were unjust and unreasonable. (See FERC Upholds ISO-NE New Entry Pricing; Rejects Challenges by Generators.)
WILMINGTON, Del. — An initiative that would allow generators to avoid underperformance penalties in the redesigned PJM capacity market was met by pushback from members who said it was premature and could undermine the new reliability product.
The problem statement presented by Bob O’Connell on behalf of PPGI Fund A/B Development would allow generators to minimize penalties by netting them against over-performing generators.
O’Connell introduced the initiative in October, saying the Capacity Performance rules allow companies with multiple generators to offset poor performance with over-performing units but does not allow after-the-fact offsets, such as bilateral trades, that could help smaller generators. (See Generators Seek to Reopen PJM Capacity Performance Rules.)
“I’m not sure why it makes sense to the market to retroactively switch around performance,” Market Monitor Joe Bowring said during a discussion at the Markets and Reliability Committee meeting. “Capacity Performance is about performing at the time you’re supposed to perform.”
Bankruptcy Threat
“We have a performance obligation to meet those,” responded O’Connell, who agreed to delay a vote on the initiative to try and address stakeholder concerns. “But to the extent that a unit has a legitimate problem that forces it to be out of service during one of these periods of time, the exposure that unit faces with possibly having to buy back its position in real time and pay a penalty … exposes it to financial stress.
“It doesn’t make sense to push that financial stress to the point that they can’t meet their obligations financially. … Sitting back until half a dozen units go into bankruptcy is something that’s not effective from a reliability standpoint or an investment standpoint.”
O’Connell said customers ultimately would benefit because the proposal would allow generators to reduce the risk premiums they will otherwise include in their offers.
“The only way to handle underperformance now is to write a check,” he said. “Give the insurance company a way to physically offlay that risk.”
Tangible Problem?
Rene Demuynck of the New Jersey Board of Public Utilities asked for proof of a problem or of consumer benefit.
“We’re at a loss as to what the failure of Capacity Performance is right now except to avoid the obligation that you want to avoid and cleared the market on,” he said. “What is the tangible problem?
Storms flooded Central Maine Power’s substation in Bath in September 2015. Source: Central Maine Power
“Consumers are being asked to pay upfront with the understanding that units would offer their capacity and, when most needed, deliver the capacity,” he said. “I would suggest that the risk of negative penalties would be substantially diminished, and therefore the incentive to perform would be substantially diminished. There’s no perceived reason we can see to even consider this, and before [FERC] addresses other issues that are pending.”
Susan Bruce, of the Industrial Customer Coalition, said the problem statement was one-sided.
“When we talk about Capacity Performance, we talk about risks and rewards,” she said. “I see this as looking at the risk side.”
While there may be legitimate issues there, she said, “This is so narrowly drawn that it doesn’t look at the other side of the equation, the customer side of the equation. … There’s nothing in this to recognize the other side of the ledger.”
O’Connell protested that since he introduced the idea for the problem statement at the September MRC meeting, he hadn’t received any calls or questions about how it might be changed to include the customer side. “How long do I have to wait?” he asked.
“At that last meeting there was a chorus of concern,” Bruce responded. “To be honest, I was sort of hoping it would go away.”
Brian Garnett of Duke Energy supported the problem statement, saying it would be a way for smaller generators to hedge financial risk in the way that larger generators can.
Alan Ellison of Veolia added that his company’s Grays Ferry Cogeneration plant in Philadelphia could go bankrupt if it stumbles in the new market.
Premature
Jim Jablonski of the Public Power Association of New Jersey said the problem statement was premature.
“Is it time to be tweaking it already?” he said of Capacity Performance. “Or should we wait for a sensitivity analysis?”
“PJM does have some concerns regarding the substance of the problem statement,” said Stu Bresler, PJM senior vice president for markets, noting that a fundamental piece of the new product’s design is unit-specific evaluation of performance.
“I don’t have an opinion how long we should wait,” he said. “But I certainly agree that experience would be helpful.”
The committee plans to vote on the problem statement at its December meeting.
PJM is entitled to recoup $28 million in line-loss credits paid to virtual traders, FERC ruled last week, reaffirming a 2011 decision that the D.C. Circuit Court of Appeals ordered it to justify.
In its response to the court’s 2013 remand, the commission found that repayment of the refunds would not have a negative impact on the PJM market (EL08-14). If anything, FERC said, “recoupment will have a positive effect on the market because market participants know they will not be permitted to retain erroneously paid refunds.”
PJM told the commission that it has already recovered $9 million of the approximately $37 million the RTO paid out to virtual traders through its marginal loss surplus allocation (MLSA), which refunds a portion of transmission loss charges to companies who contribute to the fixed costs of the grid.
PJM collects transmission loss charges to account for electricity lost as it flows over the lines, but because the RTO treats every transmission as the last in the system, its collections exceed actual losses. MLSA was approved by FERC in 2006 to account for this.
FERC decided in 2008 that up-to-congestion traders were entitled to the refunds but reversed its policy in 2011. The D.C. Circuit upheld the reversal but told the commission it had to justify why the traders should be required to pay back their refunds. (See Split Decision for Financial Traders on PJM Line-Loss Collections.)
“We have determined that the virtual marketers … should be required to repay refunds, with interest, to put the parties back in the positions in which they would have found themselves if the commission had not erred in requiring refunds in the first place,” FERC said.
In its remand, the court agreed with virtual traders Black Oak Energy, EPIC Merchant Energy and SESCO Enterprises — whose December 2007 complaint originally spurred FERC to allow them to collect refunds — that the commission’s order to repay the refunds threatened to undermine the markets.
“Recoupment interjects regulatory uncertainty into a setting in which participants rely on the finality and predictability of commission rulings to assure a well-functioning marketplace,” the companies told FERC in 2014. They complained that the order reflected a new policy, one without any time limits, parameters or sufficient notice.
FERC said, however, that it found sufficient legal precedent for its decision, citing cases in which it has required parties be made whole after it had made an error.
The commission also said that the companies “were on notice that the refunds paid based on the initial commission order were in question” and that they “had sufficient reason to preserve those funds in the event that the commission (or a court) subsequently reversed the commission’s initial determination.”
A Long, Messy History
FERC’s 2011 reversal resulted in a Pandora’s Box of market manipulation cases for the commission’s Office of Enforcement.
The company is now battling FERC in federal court over the commission’s effort to collect $34.5 million in penalties and disgorged profits. In a brief to the court filed last month asking it to dismiss the case, Powhatan argued that FERC “approved the inclusion of virtual traders in the allocation of [transmission-loss credits] with no limitation other than that the traders pay into the fixed costs of the system, which as the commission expressly recognized, would include UTC transactions.”
“Despite having had the opportunity to circumscribe the very conduct at issue in this matter, the commission did not ask PJM to limit or qualify the virtual traders’ receipt of rebates for UTC transactions, nor did the commission issue any pronouncement or order advising virtual traders that it would consider trading for the rebates wrongful conduct,” Powhatan told the Eastern District Court of Virginia.
FERC countered in its own brief, saying that it had rejected an MLSA method that credited all virtual transactions for fear of it leading to an increase in trades meant solely to cash in on the credits. “It would be impossible for a reasonable person acting in good faith to read these orders and conclude that the commission was indifferent to whether traders engaged in circular trades solely to collect MLSA, regardless of whether those trades paid for transmission or not,” FERC told the court.
City Power Marketing, fined $15 million for similar allegations, filed a motion in the D.C. Circuit Nov. 2 to dismiss the case. In September, FERC issued the same charges against Coaltrain Energy. (See FERC Charges Third Firm with UTC Scam in PJM.)
FERC last week approved SPP’s request to correct and resettle $13.1 million of transmission-service invoices dating back to 2009, waiving a one-year limit in the RTO’s Tariff. “The requested waiver is a one-time request related to [discrete] software issues, which SPP has resolved,” FERC said (ER15-2295).
Approximately $4.4 million of resettlements outside the one-year limitation date back to 2012, when SPP told FERC a transmission customer’s inquiry led to the discovery of miscalculations of transmission losses and reactive compensation across DC ties with ERCOT and the Western Area Power Administration. The RTO said the software error affected invoices between January 2009 and May 2013.
FERC’s Nov. 20 ruling said Baten’s reading of a provision in Entergy’s system agreement was “unreasonably narrow.” It said adopting his interpretation would negate the inclusion in the bandwidth formula of other production-related costs that were just and reasonable, and found Entergy’s proposal to include Little Gypsy cancellation costs in the bandwidth formula consistent with the system agreement.
