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.
The owner of a Massachusetts generating plant says ISO-NE is forcing it to pay millions in unnecessary capacity costs because the RTO mistakenly underestimated the plant’s capacity.
GenOn Energy Management, a unit of NRG Energy, asked the Federal Energy Regulatory Commission last week for relief from what it called an “anomalous, illogical and patently unfair circumstance” (EL15-57).
Canal Generating Plant
GenOn said ISO-NE credited its Canal 2 oil- and gas-fired generator in Sandwich, Mass., with capacity of only 303 MW — rather than the plant’s actual 556.5-MW output — in the March annual reconfiguration auction (ARA) for the 2015-2016 capacity commitment period.
As a result, the RTO submitted a demand bid on GenOn’s behalf for the difference, forcing the company “to buy out of a capacity supply obligation that Canal 2 is fully capable of fulfilling.” Only a portion of the demand bid cleared because supply offers filled only two-thirds of the demand bids entered.
The company redacted specifics of how much it estimated the error could cost it, but based on the ARA’s clearing price of $11.466/kW-month, and the prorated apportionment of cleared bids, GenOn could be forced to spend more than $22 million.
GenOn said the plant’s output was derated after the failure of a step-up transformer in July 2013, but that it returned to full capacity in May 2014, as documented by the RTO’s capacity audits. The company noted that it offered the plant’s full capacity in Forward Capacity Auction 9 in February.
The company asked FERC to force the RTO to correct the “obvious mistake on ISO-NE’s part” or grant it a waiver to allow it to escape the capacity charges.
It asked for FERC action by May 25 so that ISO-NE can ensure that the appropriate capacity supply obligations are in place before the beginning of the 2015/16 capacity commitment period on June 1.
MISO transmission owners have told the Federal Energy Regulatory Commission it should order only a modest reduction in their base return on equity to 11.39%, not the 9.15% sought by industrial customers.
On April 6, the TOs filed an analysis contending 11.39% represented “a logical and supportable estimate of the cost of equity.” Omitting the FERC-approved ROEs for ITC Holdings — the only publicly traded transmission-only company in the U.S. — would result in an “absolute minimum” base ROE of 10.8%, the analysis said.
MISO industrial customers initiated the ROE dispute last fall, contending that transmission operators’ current base return on equity — 12.38%, except for American Transmission Co. at 12.2% — is too high (EL14-12).
The industrials contend the base ROE for TOs should not exceed 9.15%, citing changes in financial markets and other factors. They say the lower base ROE would cut transmission rates by about $327 million annually.
The dispute last year went into settlement discussions, but talks broke down in December.
After it became clear the case would not settle, the MISO Public Consumer Group sector joined in the fight, in what is its first-ever litigation in a FERC rate case.
In February the sector — which includes both non-profit groups and government agencies that represent consumers in utility cases before state regulators — asked MISO for $200,000 to help cover its legal costs in the dispute. (See MISO Advisory Committee Briefs.)
MISO spokesman Andy Schonert said last week that the RTO “continues to consider stakeholder feedback [on the request] and will be finalizing [its] decision quickly.”
On April 3, the consumer advocates asked FERC for approval to amend the group’s intervention by adding the Arkansas Attorney General’s Consumer Utility Rate Advocacy Division; the Kentucky Attorney General’s Office of Rate Intervention; the Louisiana-based Alliance for Affordable Energy; the Montana Consumer Counsel; and the Illinois Attorney General.
“As the outcome of the joint consumer advocates funding request has not yet been determined, it is even more important to broaden consumer advocate engagement in this proceeding in order to build up resources to support the Consumer Advocates’ participation in this case,” wrote Jennifer Easler, an attorney in the Iowa Office of Consumer Advocate.
The dispute follows FERC’s ruling last June that introduced a new, two-step method for calculating transmission owners’ ROEs. Ruling in a case involving New England TOs, FERC tentatively set the “zone of reasonableness” at 7.03 to 11.74%.
The next year will be a good one for natural gas-fired generators in PJM, according to Morningstar Commodities Research.
A new report by Morningstar analyst Jordan Grimes predicts on-peak prices at PJM’s West Hub will result in “historically high” spark spreads in delivery year 2015-16. Spark spread, a measure of gas plants’ gross profit margin, is the difference between the price received by a generator for power and the cost of the gas needed to produce it.
Grimes says physical reserve margins will tighten due to the retirement of more than 10,000 MW of older coal, gas and oil capacity before June 1.
“New combined-cycle capacity will replace some of this lost capacity, but much of the physical capacity will be replaced with demand response, renewables and expected imports from neighboring ISOs,” he wrote. “When DR replaces physical capacity, it will steepen the supply curve at the same time physical reserve margins drop this summer.”
For a gas plant with a 7,000 Btu/kWh heat rate purchasing gas at Tetco-M3 and selling power at PJM West, that could lead to spark spreads averaging $25/MWh in calendar year 2015 and $22/MWh in 2016, Grimes predicts.
But he says spreads will decline to $18 in 2017 and $16 in 2018 as more new combined-cycle plants are built in PJM and pipeline expansions allows Marcellus gas producers to obtain higher prices from more distant customers.
“There are a few scenarios … that would help keep spark spreads elevated in 2017 and 2018, but the most likely scenario is lower spark spread clears, given the new, more efficient supply stack and higher Tetco-M3 gas prices,” Grimes said.
An unexpected geomagnetic disturbance (GMD) March 17 caused brief spikes on PJM’s grid but no operational problems, RTO officials told the Operating Committee last week.
Some of PJM’s approximately 50 geomagnetically induced current (GIC) meters recorded spikes of more than 20 amps, but the jumps were short-lived and did not cause PJM to direct conservative operations.
The National Oceanic and Atmospheric Administration, which normally provides one to three days’ advance notice of such events, didn’t warn PJM and other grid operators until the morning of the 17th, said Chris Pilong, manager of dispatch.
NOAA predicted “a glancing blow” centered at 50 degrees latitude — near Winnipeg, Manitoba. As it turned out, the solar storm was a bit more intense than expected and centered a bit farther south, Pilong said.
Still, the incident did not pass PJM’s threshold for initiating conservative operations — a rise of 10 amps for more than 10 minutes. Pilong said the longest spikes lasted no more than four minutes.
“This is the highest measurement I can recall seeing in some time and we saw no impact on the system,” he said.
NOAA initially predicted a G-3 (strong) event for three hours beginning at 8 a.m. ET. It upgraded the storm to a G-4 (severe) with a lower latitude of 45 degrees — near Montreal — and a six-hour duration.
The GIC meters recorded their biggest spikes between 9 and 10 a.m. and 7 and 7:30 p.m. (See graphic.)
The incident came less than two weeks before the North American Electric Reliability Corp.’s Geomagnetic Disturbance Operations Standard (EOP-010-1) took effect on April 1. The standard requires reliability coordinators to review the GMD operating procedures or processes of transmission operators (TOPs) within their areas to mitigate the effect of GMDs on the grid.
PJM: New Rule on Lost Opportunity Costs Would Exclude 1/5 CTs
About 20% of PJM’s combustion turbines, representing 30% of its CT capacity, would be barred from receiving lost opportunity costs under a rule change awaiting a shareholder vote, PJM officials told the OC last week.
Adam Keech, director of wholesale market operations, said PJM conducted the analysis after the Markets and Reliability Committee last month tabled voting on the proposal.
The delay came after some stakeholders complained that the changes — which would generally limit lost opportunity costs to units with start-up and notification times of no more than two hours and minimum run times of two hours or less — were too restrictive. (See PJM Tables Rule Change on CT LOCs.)
Keech said that if the minimum-run-time threshold were increased to four hours from two, only 10% of CT units and capacity would be excluded from lost opportunity costs.
PJM officials told the OC they had no operational concerns about the changes.
One generation operator, who declined to be quoted by name, said the new rules would create “perverse incentives” for generator operators, resulting in some units running under self-schedules for an additional hour after the two-hour limit. “I will submit a schedule that meets your payment parameters, but on operations I need to do what I need to do,” he said.
“Instead of using a carrot approach, you’re using a stick approach,” he added.
Keech said that the change, which is supported by PJM and the Independent Market Monitor, was intended to eliminate incentives at odds with PJM’s needs. Under the current rules, he said, “you get paid more if you don’t run [in real-time] than if you do.”
Louis Slade, a senior policy manager for Dominion Resources, questioned whether PJM’s data would be accurate in the future, saying most new CTs are 150 MW or larger and have minimum run times of longer than two hours. “Two hours potentially puts a lot of the newer CTs outside of that range,” he said.
Director of Stakeholder Affairs Dave Anders said the Energy Market Uplift Senior Task Force, which overwhelmingly approved the proposed change in February, may consider “friendly amendments” at its April 17 meeting.
The MRC is expected to vote on the issue at its next meeting, April 23.
Too Much of a Good Thing? PJM Concerned Fast Response Regulation Crowding Out Traditional Resources
PJM operators are concerned that fast response regulation resources are taking too large a share of the RTO’s overall regulation response.
PJM’s Danielle Martini presented a proposed problem statement on the issue to the OC last week.
Fast-responding RegD are providing more than 42% of total response on average, with shares as high as 70% during some events, Martini said. That leaves less room for slower-responding RegA resources.
“Too much RegD looks like it hurts performance because it affects how much RegA we procure,” Mike Bryson, executive director of system operations, explained after the meeting.
PJM is considering whether to use a different regulation signal for energy-limited resources such as participating in the regulation market.
“This scenario is seen most frequently when the RTO experiences high or low [area control error] during periods of rapid load changes during the morning and evening periods,” the problem statement said. “During these times, the regulation signal is utilized to maintain ACE control if the load ramp briefly and instantaneously ‘slows down’ or ‘speeds up.’ During these times, larger sized units are coming on line and offline (hydro, CTs, etc.) to keep up with the load, and regulation is critical in correcting for the instantaneous changes in load and generation.
“When the regulation signal ‘times out’ for RegD resources and there is a large amount (>42%) of RegD providing the regulation service, the dispatcher is left with limited resources with which to maintain control of the system. This may lead to increased periods of ACE/BAAL excursions and increased reliance on synchronized reserves to supplement the temporarily depleted regulation reserves.”
PJM Ponders Expansion of Winter Generator Testing
PJM is considering stakeholder suggestions that it expand the winter generator testing it initiated last winter.
That testing was voluntary and limited to units that hadn’t run for the prior two months. It was credited with reducing generator outages to a peak of 10% in January 2015, compared with a high of 22% a year earlier.
Mike Bryson, executive director of system operations, told the OC that some stakeholders have suggested the testing be made mandatory.
In early November, PJM identified about 55,000 MW of generation that was eligible for testing because it had not operated for the prior two months. The number dropped to about 44,000 MW after some of the units were dispatched during an early November cold spell.
Owners of about half of the remaining units submitted them to PJM for testing, but the RTO ended up testing only about 9,000 MW because of a 1,000-MW cap on tests per day and because warm weather prevented testing on some days.
The temperature threshold “knocked most of the days out” for testing in the Dominion zone, Bryson said.
PJM officials plan to discuss the issue internally before bringing a proposal to stakeholders, Bryson said.
New Info on Planned Outages to be Shared
PJM plans to start posting additional information on scheduled transmission outages in its OASIS system in response to requests for such details.
Beginning with the third-quarter eDart release in September, the following information will be available: the queue number; the time that the outage equipment can be returned to service at PJM’s request; and a “questionable approval” indicator, which will inform market participants that the outage may not be approved by PJM.
