On Feb. 12, the Federal Energy Regulatory Commission asked for comments on the pros and cons of six potential rule changes intended to push PJM and MISO to create cross-border transmission projects (EL13-88). The changes were proposed by Northern Indiana Public Service Co. (NIPSCO) in December 2013.
The commission asked commenters to opine on the costs and technical feasibility of implementing requirements that MISO and PJM:
Run their cross-border transmission planning process concurrently with the RTOs’ regional transmission planning cycles, rather than after them.
Develop a single model that uses the same assumptions in the cross-border transmission planning process. Until the joint model is developed, the RTOs would be required to ensure consistency between their planning analyses and apply their reliability criteria and modeling assumptions consistently.
Use a common set of criteria in evaluating cross-border market efficiency projects.
Consider all known benefits, including avoidance of future market-to-market (M2M) payments made to reallocate short-term transmission capacity in real-time operations, when evaluating cross-border market efficiency projects.
Establish a process for joint planning and cost allocation of lower-voltage and lower-cost cross-border upgrades.
Amend their Joint Operating Agreement to improve the processes for new generator interconnections and generation retirements.
The commission also asked for comments on whether persistent M2M payments indicate the need for new transmission and on NIPSCO’s and others’ estimates of M2M payments. FERC also asked for examples of projects considered but not developed under the cross-border transmission planning process and the reasons why they were not completed.
ISO-NE has proposed two new capacity zones for Forward Capacity Auction 10 next year (ER15-1462).
The petition filed with the Federal Energy Regulatory Commission on April 6 reflects where the RTO expects transmission constraints to be most severe in the 2019-2020 delivery year. ISO-NE requested that FERC approve the proposed zones by May 29, before the June 1 deadline for qualifying existing capacity and submission of de-list bids.
The boundary of the proposed Southeastern New England zone would combine the northern and western borders of the NEMA/Boston zone and the western board of the SEMA/RI zone.
One new potential zone is Southeastern New England (SENE), a combination of the existing Northeastern Massachusetts/Boston zone with Southeastern Massachusetts/Rhode Island. The other new zone, Northern New England (NNE), is a combination of the existing Maine, New Hampshire and Vermont load zones.
ISO-NE said these are “potential” new capacity zones. “At this phase of the zonal development process, the appropriate boundaries are simply being defined so that if these capacity zones are needed, they can be modeled in the auction,” said Alan McBride, director of transmission strategy and services.
No changes are proposed with the current West-Central Massachusetts or Connecticut zones.
SENE is proposed as an import-constrained capacity zone, while NNE is proposed to be export-constrained.
For FCA 9 the zones were: NEMA/Boston, SEMA/RI, Connecticut and Rest-of-Pool, which includes West-Central Massachusetts, Vermont, Maine and New Hampshire.
The RTO conducts an annual assessment of transmission transfer capability to identify system weaknesses as part of its New England Regional System Plan. Modeling showed the effects of recent and pending plant closures, including the Vermont Yankee nuclear plant last year and the 2017 planned mothballing of the 1,535-MW Brayton Point generation station in Massachusetts.
Transmission upgrades planned for eastern Massachusetts will allow power to move more freely within the proposed zone, but constraints were found where the new, larger zone connects to the others. “These constraints are such that new, qualified resources located in either zone would be helpful in addressing the overall constraints. That is, new resources in SEMA/RI would be helpful in unloading the constraints,” according to the filing.
In NNE, power flow studies indicate an existing transmission interface is located along the southern borders of New Hampshire and Vermont and the northern border of Massachusetts. Without Vermont Yankee and Brayton Point, “the North-South flows are now forecast to be more concentrated along the lines connecting southeastern New Hampshire with eastern Massachusetts,” the RTO said.
A federal appeals court has rejected challenges to the Lower Hudson Valley Capacity Zone in New York (14-1786).
Utility companies and the New York Public Service Commission had appealed an August 2013 order by the Federal Energy Regulatory Commission creating the zone, saying it would lead to a windfall for power generators. (See New Yorkers Upset over NYISO Capacity Zone.)
A three-judge panel of the U.S. Second Circuit Court of Appeals ruled in favor of FERC on April 2 in a 61-page opinion.
“We conclude that FERC articulated sound economic principles supporting the creation of the Lower Hudson Valley Zone and satisfactorily explained how those principles justified its conclusion,” the court said.
The options for the losing parties are to ask for an en banc rehearing before the entire court or to directly petition the U.S. Supreme Court.
“We are disappointed, as the capacity zone has unfairly and artificially raised energy prices for homes and businesses in our service territory. We are reviewing the court’s decision, however our legal options are very limited as there are no reasonable or promising actions available to us,” said Central Hudson Gas & Electric spokesman John Maserjian.
Central Hudson says monthly bills have increased by 6% for residential customers and 10% for large industrials.
NYISO, in response to previous FERC orders, created the zone in the counties north of New York City in August 2013. The lawsuit challenging was filed after additional charges in the zone went into effect May 1, 2014.
NYISO and FERC maintained that generation resources were needed because price signals were insufficient to encourage power plant developers to site facilities there and that transmission constraints threatened reliability.
“We are not persuaded that there is anything unreasonable in FERC’s conclusion that higher prices were necessary to ensure reliability by generating accurate price signals in the long run,” the court wrote.
FERC said the congestion issue has been discussed since 2006 without a solution. Consumers have been shielded from higher prices since that time, it noted.
The companies and the PSC had argued that proposed transmission projects would relieve the constraints. (See Tx Plan to Open NY Choke Points Without New ROWs.) Another project would create a corridor from the Canadian border to New York City, making renewable energy generation from upstate more readily available.
The court sided with FERC’s contention that the projects have not yet been certified and that FERC “rationally explained its decision to act according to existing market conditions rather than speculative future conditions.”
VALLEY FORGE, Pa. — Stakeholders last week continued their debate over PJM’s proposal to create “historic” capacity transfer rights for some load-serving entities, with the Independent Market Monitor cautioning the Market Implementation Committee that the new Tariff language would constitute a “fundamental change.”
The proposal resulted from a problem statement approved by the MIC in December to review modeling practices that the RTO said may be shortchanging loads with transmission agreements that pre-date the RTO’s capacity market.
The changes would allow market participants to use generation resources outside of their locational deliverability areas (LDA) to meet their internal resource requirements if that external capacity agreement was in place before June 1, 2007, when PJM implemented its Reliability Pricing Model. Previously, there was no locational differentiation made among capacity resources.
The proposal would address the situation faced by the Illinois Municipal Electric Agency, which last year won a federal waiver to allow it to use capacity resources outside of the Commonwealth Edison LDA to meet its internal resource requirement in serving its Naperville, Ill., load.
The Federal Energy Regulatory Commission granted IMEA a waiver for the 2017/18 delivery year after the ComEd LDA last year was modeled for the first time with a separate variable resource requirement curve (ER14-1681).
In January, however, the commission rejected IMEA’s request to continue use of the waiver for future delivery years, saying it had enough time to prepare to meet its internal resource requirement (ER14-1681-001). The commission also rejected a specific waiver request for the 2018/2019 delivery year (ER15-834). (See Illinois Regulators, IMM Line Up Against IMEA Capacity Waiver Request.)
PJM estimates 1,037 MW of historic external resources would qualify under its proposal: 122 MW in the DOM zone, 533 in COMED, 261 in AEP and 121 in DAY.
“This isn’t a piddling amount of megawatts,” GT Power Group’s Dave Pratzon said.
One stakeholder, who declined to be identified by name, said the rule change would be fair if it protects the property rights of load-serving entities that had funded transmission upgrades that increased the capacity emergency transfer limit (CETL) into their region.
But he said it may be “inequitable” if it also covers those whose only claim is a firm transmission reservation that predates RPM. Others observed the change would give such LSEs a preference over their neighbors for available transmission capacity.
Pratzon said he was concerned that PJM would be unable to set a “bright line” to distinguish between entities that have legitimate claims from those that don’t.
“It does seem to be creating a preferential set of rights for a certain group of people. I wouldn’t want us to set something up where in effect we’re giving people a second bite of the apple for certain decisions they made in RPM that they wish they hadn’t made,” he said. “I want to make sure we’re not putting ourselves on a slippery slope to other requests for special treatment.”
Mark Hanson, an economic analyst for the Illinois Commerce Commission, said the proposal goes too far. “It seems like maybe [entities such as IMEA have] gone from being too much at risk to being immunized from risk,” he said.
Market Monitor Joe Bowring said the change “represents a very substantial, fundamental change to the way [capacity transfer rights] are allocated within LDAs.”
Stu Bresler, PJM vice president of market operations, said the proposal would apply to a “well-defined subset” of LSEs. “It could never grow. We’d never have a new one,” he said.
Bresler said PJM will provide additional information on its proposal at next month’s MIC meeting.
The union representing workers at the Brayton Point Power Station say the plant’s pending closure caused massive price spikes in recent capacity auctions and that the results of the ISO-NE Forward Capacity Auction 9 should be voided (EL15-1137).
Utility Workers Union of America Local 464 filed a protest Monday with the Federal Energy Regulatory Commission seeking to cancel the auction that was held in February for the 2018-2019 capacity commitment period. Comments on the ninth auction were due Monday. (See ISO-NE Files Capacity Auction Results; Comments due April 13.)
They charge that the plant’s former owner, Energy Capital Partners, removed the 1,510-MW plant in Somerset, Mass., from FCA 8 and FCA 9 to inflate prices offered for other generation plants that it owned. ECP in 2013 said the plant would close in 2017.
“Energy Capital Partners intentionally raised the prices to be paid by purchasers of capacity market-wide in the FCA 8 auction by approximately $1.6 billion to $2.4 billion — an approximately 200% increase over prices in the prior annual capacity auction — and increased market-wide capacity prices by an additional approximately $1 billion in the FCA9 auction,” the protest states.
Results at FCA 9 came in at just about $4 billion, $1 billion higher than FCA 8 from February 2014. FCA 8 saw prices triple, to just over $3 billion from the previous year’s results of about $1 billion.
UWUA says the “illegal” actions by ECP were a violation of the ISO-NE Tariff. Retirements of generation plants that result in higher prices and profits for the owners’ other plants are only allowed if the closed plant was uneconomic on its own. Brayton Point’s sale to Dynegy was announced in 2014 as part of multi-state acquisition of four other plants totaling 1,902 MW. (See Dynegy Becomes New England Player Overnight.)
Dynegy reiterated its intention to close Brayton Point immediately after the sale was announced. The union cited a presentation to investors made last summer by Dynegy that said Brayton Point would have operating profits of $105 million in 2015.
The union made a similar protest a year ago when FERC began its review of FCA 8. The results became effective as an operation of law when the commission was deadlocked 2-2. (See FERC Commissioners at Odds over ISO-NE Capacity Auction.)
An amended complaint filed by the union in February did not prompt any further commission action (ER14-1409).
The U.S. Supreme Court will consider the Federal Energy Regulatory Commission’s appeal of a ruling voiding its authority over demand response in its conference April 24. At least four of the nine justices must agree to hear the case (14-840) for it to proceed.
FERC filed a petition for a writ of certiorari in January, contending that the D.C. Circuit Court of Appeals erred in its 2014 ruling (Electric Power Supply Association v. Federal Energy Regulatory Commission) that FERC lacked authority under the Federal Power Act to regulate energy market payments to DR providers.
The ruling, which voided FERC Order 745, was limited to the energy markets. But some stakeholders say the ruling also invalidates the commission’s regulation of DR in capacity markets. On March 31, FERC rejected as premature PJM’s proposed contingency plan for including demand response in its May Base Residual Auctions in the event the D.C. Circuit’s ruling is allowed to stand. (See FERC: PJM Demand Response Stop-gap Measure ‘Premature’.)
Wisconsin Energy Takeover of Integrys Gets OK from FERC
The Federal Energy Regulatory Commission on April 7 approved Wisconsin Energy Corp.’s $9.1 billion acquisition of Integrys Energy Group.
Wisconsin Energy is the parent of electric utility We Energies. Integrys owns the Green Bay-based electric-natural gas utility Wisconsin Public Service Corp., along with Peoples Gas.
FERC dismissed concerns raised by a consortium of municipal electric utilities that contend that the merged companies would have undue influence over American Transmission Co., noting the new Wisconsin-based utility giant plans to limit voting rights in ATC.
The deal still requires the approval of four states: Wisconsin, Michigan, Minnesota and Illinois.
Feds Consider Rules that Would Protect Bats, Hobble Wind Farms
The U.S. Fish and Wildlife Service is studying whether it needs to modify some rules protecting the Northern long-eared bat in a move that could affect wind farms. The agency announced that it would list the species as threatened.
The designation could result in regulations increasing the wind speed at which turbines are allowed to start producing energy on the theory that fewer bats will be flying when wind speeds are high. The agency is taking comments on the proposed rule changes and is expected to finalize the rules by the end of the year.
NRC Approves Use of Hotter Fuel Rods at FirstEnergy’s Perry Plant
A new type of fuel rod that has thinner metal walls encasing enriched uranium has been approved for use at FirstEnergy’s Perry nuclear generating station. The Nuclear Regulatory Commission has approved the use of the fuel rods, which should result in an increase of energy production while allowing use of less enriched uranium.
FirstEnergy is replacing about a third of the 748 fuel rod assemblies during the current refueling outage. Opponents to the plan say that the thinner fuel rod walls could present a problem moving the fuel rods in the decades to come after the rods are exhausted. NRC is currently testing the rods for long-term storage issues.
Group Says RGGI Could be Way to Meet Emissions Mandates
A New England nonprofit energy policy group has released a report that says joining the Regional Greenhouse Gas Initiative could provide a solution for Virginia to meet upcoming federal emission reduction mandates. The Acadia Center said that by joining the nine states already participating in RGGI, Virginia could have a “plug-and-play” way of satisfying the requirements of the Environmental Protection Agency’s Clean Power Plan.
“Virginia could build on this existing foundation by adopting the RGGI model rule, which would allow the commonwealth to participate in the market while preserving authority and enforcement at the state level,” according to the report.
“RGGI has been successful in the states that currently participate. It is helping to reduce carbon emissions, while offering a demonstrated record of advancing economic development, and saving consumers money on energy,” said Daniel L. Sosland, Acadia Center president.
It isn’t clear how much support such a move would have in Virginia. A bill calling for Virginia to join the RGGI never got past committee earlier this year in Virginia’s Republican-controlled legislature.
Nine states currently participate in the RGGI: New York, Maryland, Massachusetts, Maine, Delaware, New Hampshire, Rhode Island, Connecticut and Vermont. New Jersey was a member, but Gov. Chris Christie pulled the state out two years ago.
PPL Gets Approval for Transfer of Nuclear Asset to Talen
The Nuclear Regulatory Commission has approved the transfer of PPL’s Susquehanna Steam Electric Station nuclear plant operating licenses to a new merchant generation company, Talen Energy. PPL is spinning off most of its generation, which will be combined with assets owned by Riverstone Holdings, to form Talen. The new company will be an unregulated, competitive generation supplier. Allegheny Electric Coop. has a minority ownership share of the two-unit plant.
The Federal Energy Regulatory Commission and the state Public Utility Commission have approved various filings relating to the Talen spinoff. Final approval is still needed from the U.S. Department of Justice under the Hart-Scott-Rodino Antitrust Improvements act. PPL still says it expects to close the transaction by the end of June.
A Florida power trader under investigation for market manipulation over up-to-congestion trades says the transactions were lawful and that an “unfair” investigation by the Federal Energy Regulatory Commission has ruined his business. He asked for a review of his case by the full commission (IN15-5).
According to FERC’s Office of Enforcement, Stephen Tsingas and his firm, City Power Marketing, made $1.2 million in July 2010 through “fraudulent” and risk-free round-trip UTC trades placed solely to collect line-loss rebates. The allegation is almost identical to what FERC made in the pending case against Rich and Kevin Gates and their Powhatan Energy Fund.
Tsingas’ April 7 filing is in response to the demand by FERC Enforcement that it show why he and City Power shouldn’t return the profits and pay $15 million in fines.
Tsingas’ defense is similar to that of the Gates brothers: He argues that when the trades were undertaken there was no direct prohibition of them. When PJM’s Independent Market Monitor raised objections to the transactions, Tsingas says, he and City Power discontinued them.
FERC investigators cited instant messages such as these in July 2010 in their case against City Power.
Tsingas also denied an allegation that he concealed documents during the investigation. Tsingas and his attorneys say a series of instant messages that FERC purports to show collusion are taken out of context.
Tsingas’ legal team — which includes Todd Mullins, a former branch chief in the Office of Enforcement’s Division of Investigations — says the investigation effectively put City Power out of business.
“Staff’s investigation of this handful of trades has destroyed CPM,” they wrote. “Once a company with eight employees and gross revenues exceeding $8 million annually, CPM now only has one employee — Mr. Tsingas.
“The stress of an investigation that has lasted almost five years, along with the enormous expenses incurred as a result, have ruined the company even before any tribunal — judicial or administrative — has had the opportunity to determine the merits of staff’s accusations.”
The crux of the defense is that to be prosecuted for manipulation, there must be a showing of “fraud or deceit.” Tsingas claims that when the trades were undertaken there had not yet been a determination that the trades were anything but legal transactions that may have taken advantage of a market weakness.
“There was no false information injected into the marketplace,” Tsingas’ lawyers wrote. “There was no artificial price formation. There was no violation of the [commission’s] Anti-Manipulation Rule. CPM traders were simply responding to the predictable incentives created by the market.
“The commission cannot and should not turn into a violation every case in which [a] participant trades in a manner consistent with the rules as then written and involving no falsity just because the trader may have had a motive for the trade that was not what the commission … had in mind,” they argued.
The Federal Energy Regulatory Commission says a filing made by NYISO to calculate payments for voltage support services (VSS) is deficient (ER15-1042).
The commission Friday requested more information before it can consider amendments to NYISO’s Market Administration and Control Area Services Tariff.
NYISO proposed paying VSS providers $2,592/MVAr for both leading and lagging capability, with annual increases based on the consumer price index (CPI). MVAr is the unit of measurement for reactive power capability. (See NYISO Rejects Protests on Voltage Compensation.)
FERC asked NYISO for more explanation of the methodology and assumptions used to determine the proposed rate. It also ordered the ISO to provide documentation demonstrating that the proposed amendments maintain the approximate total dollar value of the current VSS program in the near term.
The Independent Power Producers of New York and Dynegy Marketing and Trade filed separate protests asking FERC to order the ISO to increase the compensation rate to reflect inflation since the existing rate was set in 2002.
Opponents of a financial lifeline for the R.E. Ginna nuclear plant were rejected Monday in their bid for more time to prepare their challenges.
Environmentalists and industrial consumers contended the current schedule will deny ratepayers due process in a case that could cost them $175 million.
The New York Public Service Commission has ordered initial “issue statements” by April 15 in a review of the ratepayer impact of a reliability support services agreement between Rochester Gas & Electric and Exelon’s Constellation Energy Nuclear Group, the plant’s owner. (See Action on Ginna RSSA Delayed 4 Months.)
The PSC ordered the utility to make a deal to keep the plant operating after regulators and NYISO determined the plant was needed to maintain system reliability. A flurry of filings have been made over the past two weeks as supporters and opponents of the deal vie for position (14-E-0270).
Those filings “have not established a basis for us to conclude that an extension of the deadline for submitting issue statements is necessary,” administrative law judges overseeing the case wrote. They also cited the coming summer peak demand, the reliability needs provided by the plant and Ginna’s right to cancel the agreement on July 1 as reasons to keep to the established schedule.
The judges said they were being asked to make rulings on the merits of the agreement in what is meant to be a procedural phase of the case. “We must establish a schedule that preserves the full range of possible outcomes for commission review and decision, without, in practical effect, deciding substantive issues,” they added.
Opponents asked the PSC for more time to make their case against the deal, while the utility, plant owner and PSC staff want to maintain a schedule that would close the case by July 29. If approved, the agreement would be retroactive to April 1 and last through September 2018.
The Alliance for a Green Economy and Citizens Environmental Coalition joined the opposition in an April 1 filing in which they also challenged the hearing schedule. The groups said the April 1 effective date of the contract was arbitrary.
“It is unreasonable to saddle Rochester-area customers with retroactive costs and interest payments that will start accruing before there has been time for [the] public to comment on the proposal or for the Public Service Commission to review the case,” they said.
They added that in a “major rate proceeding,” the PSC staff and interested parties have three to four months to conduct discovery. “The relief sought in this case is distinguishable from that which is sought in a typical major rate filing,” the judges wrote, citing the PSC order and the limited issue it posed.
The Utility Intervention Unit of the state’s Consumer Protection Bureau also challenged the effective date, “which was arrived at without the benefit of the parties’ input, [and] should not be used as a justification for limiting the parties’ due process opportunities to participate effectively in this proceeding.”
About 60 commercial, industrial and institutional customers said they support a one-month delay as a “reasonable” time frame to resolve issues before hearings with administrative law judges.
The PSC staff disagreed, saying that the schedule — which allowed 45 days for public comments — meets state law and balances the need to provide adequate time for the public to comment.
VALLEY FORGE, PA — Two competing transmission developers are challenging PJM’s selection of Dominion Resources and FirstEnergy to resolve reliability problems near Pratts, Va. (See Dominion, FirstEnergy Recommended for Pratts Solution.)
In its letter, dated March 24, Northeast Transmission, a unit of LS Power, said the two proposals it submitted are more efficient and cost-effective than PJM’s choice.
“NTD does not believe that PJM appropriately considered the cost cap provided by NTD relative to cost ‘estimates’ for alternative proposals,” it said.
It also asked PJM to consider two project combinations, either of which it said would save an estimated $28.8 million to $58.8 million and provide cost containment. One of the combinations also would offer reduced risk through use of an existing right-of-way, the company said.
ITC’s letter, dated April 7, called on PJM to reconsider its proposal, which it called “nearly identical” to the one from Dominion and FirstEnergy.
“To resolve this issue equitably, and ensure the evaluation of proposals on an even playing field, we request the PJM perform additional analysis to compare the ITC proposal with the Dominion-FirstEnergy proposal before making a recommendation to the PJM board.”
Four developers suggested 16 proposed solutions, but PJM concluded only six of the proposals solved the violations. PJM said the Dominion-FirstEnergy proposal was selected in part because the companies own the substations involved and most of the rights-of-way required. In addition to project risk, PJM said it considered performance and cost-effectiveness in its selection.
Paul McGlynn, PJM general manager of system planning, told the Transmission Expansion Advisory Committee that planners will review the competitors’ letters and consider changes to their recommendation “if they are in fact warranted.”
McGlynn said planners will return the issue to the TEAC for another discussion before making a final recommendation to the PJM board.
Sharon Segner, a vice president for LS Power, questioned why the Dominion-FirstEnergy proposal should receive a preference for owning substations and rights-of-way when any developer selected would be able to invoke eminent domain to acquire needed land. She added later that Virginia has established precedent that new entrants can obtain public utility status.
“You’re certainly entitled to your opinion,” McGlynn responded.
Segner also said PJM should consider identifying the top three or four most important criteria it will consider when it issues future competitive solicitations, as she said is the practice in CAISO’s Order 1000 process.
McGlynn said performance, cost effectiveness and risk will always be top priorities although their relative weighting may vary from project to project.
