Page 1556 – RTO Insider

May 11, 2015June 15, 2023

Stakeholders Debate Need for Clean Power Plan Reliability Safety Valve

By Rich Heidorn Jr.

WASHINGTON — In the 11 months since the Environmental Protection Agency proposed its Clean Power Plan, the idea that the final rule should include a reliability “safety valve” has become an article of faith among utility, state and RTO officials.

Count former state regulator Sue Tierney among the nonbelievers.

“I don’t think a reliability safety valve is needed because … we have those mechanisms in place today,” Tierney told a Bipartisan Policy Center forum Friday. “We have reliability-must-run contracts. We have ways to address voltage support. We have ways to address inertia. … We will not allow a plant to retire if it’s needed for reliability purposes.”

John Moore, NRDC (reliability safety valve) — John Moore, NRDC

Tierney, senior advisor for the Analysis Group, and John Moore, senior attorney for the Natural Resources Defense Council’s Sustainable FERC Project, were in the minority in cautioning against a mechanism for providing relief from the EPA’s carbon emission rule.

Indicating their support at the forum were Gerry Cauley, CEO of the North American Electric Reliability Corp.; PPL CEO William Spence; Michael Dowd, director of the Virginia Department of Environmental Quality’s air division; James W. Gardner, vice chairman of the Kentucky Public Service Commission; Craig Glazer, PJM’s vice president for federal government policy; and John Novak, the National Rural Electric Cooperative Association’s executive director for environmental issues.

Federal Energy Regulatory Commissioner Colette Honorable mostly listened and asked questions.

reliability safety valve — Jason Grumet, BPC

BPC President Jason Grumet said the forum was intended as “a constructive, messy, complicated conversation.” He opened the four-hour discussion by declaring what was out of bounds: “We are not going to debate the interim [EPA] targets. We are not going to be debating the legality of the rule. We’re not going to be debating the existential question of whether climate change exists,” he said.

Tierney began her comments by remarking that preparations for EPA’s Mercury and Air Toxics Standards also prompted apocalyptic warnings. Yet when the rule took effect April 16 — albeit, with a reliability safety valve included — the lights did not go out, she said.

“Business as usual is not assuming that the problems are going to go away,” she said. “Business as usual in this industry is making sure reliability is addressed all the time.”

Fear of Complacency

Tierney and Moore spent much of their time debating NERC’s Cauley and PJM’s Glazer.

“One thing I’d like to challenge is assertions that because the grid and the utility industry [have] been resilient in the past and resolved all problems … [they] will continue to do so,” Cauley said. “We don’t work that way. If a power company operates on that presumption we go get ‘em and fine them a million dollars a day. Because you can’t go off into unknown areas and not have a well-planned, well-operated system.”

Glazer spoke on behalf of the ISO/RTO Council, which included a detailed reliability safety valve proposal in its comments to EPA. “If we do this right, Sue is right, we shouldn’t need the reliability safety valve. But boy it is a good thing in our view to have.”

Spence, representing the investor-owned utilities of the Edison Electric Institute, agreed. “We’re not asking for a free pass,” he said. “We’re just saying if we get ourselves into a situation where we need to do something, [EPA can provide relief from compliance]. I think that’s a reasonable ask.”

“There will be nothing that will derail the Clean Power Plan quicker than having a reliability event,” he added. “So I would suggest [to] people who really want to see [EPA’s 30% emissions reduction] pushed across the finish line: We ought to have all the tools that we possibly can have.”

Novak said the mechanism could be needed if Virginia lost the North Anna nuclear plant. “What if for some reason [North] Anna goes down for several years — or like San Onofre in California, it goes down forever?” he asked. “Are there going to be sufficient offsets to make up for 1,000 MW or more of non-emitting generation? How long will it take to get that extra … energy?”

Dowd said he was concerned about relying on existing law and mechanisms to ensure reliability.

“The question of whether reliability trumps environment has not been established,” he said. “… The courts have not decided that.”

Undermining Markets

Tierney said the flexibility of the proposed rule — which would allow states to engage in interstate emissions trading and to lower emissions through energy efficiency, renewables and low-carbon fuels — provides ways to balance reliability and compliance.

Tierney said the IRC’s proposal could result in an “administrative nightmare” and undermine the discipline needed to develop market-based compliance programs.

“Just about every [concern] that I’m hearing about could be solved with market-based approaches,” she said. “The biggest thing that will be an impediment to the development of carbon markets would be a safety valve that creates the ability to leak carbon into the atmosphere.”

Glazer responded by quoting former Defense Secretary Donald Rumsfeld’s quote: “You go to war with the army you have, not the army you wish you had.”

“The reality is we are not going into this with a mandatory, nationwide [carbon] market,” he said. “This is not Waxman-Markey,” the cap-and-trade bill that failed to win Senate passage in 2010.

Cauley acknowledged that electricity markets are resilient. “But they’re not infallible, because they are limited by gas supply [and] by resources that do get retired.

“Do I want to bet the future of grid reliability five years from now, 10 years from now on a robust carbon market? I don’t think we’ve seen that yet and I don’t know that there’s any assurance that that will materialize,” he said.

No ‘License to Steal’

Glazer said the IRC’s proposal was designed with a high burden of proof and only time-limited relief to ensure it didn’t become a “license to steal.” It would require independent verification that there is a reliability problem that can’t be addressed through carbon offsets.

“If somebody can just run into the governor’s office and get a five-year, 10-year extension, this is going to be a farce,” he acknowledged.

Moore said any increased emissions resulting from such relief should be offset by reductions elsewhere.

Glazer asked FERC not to use its litigation process in any role it would have under a reliability safety valve. (See FERC Seeking Its Role on Carbon Rule ‘Safety Valve’.)

He recalled the fight over GenOn Energy Management’s coal-fired Potomac River Generating Station outside D.C., which shut down in September 2012 under pressure from environmentalists and public officials.

“Because of the ex parte rules … I couldn’t call Joe McClellan, who was [FERC’s] reliability coordinator. We couldn’t have him at meetings. FERC became irrelevant to the process,” Glazer said. “So I implore you to find creative” alternatives.

Sitting to Glazer’s left, Commissioner Honorable nodded. “Noted,” she said.

May 11, 2015June 15, 2023

PJM OC Briefs

VALLEY FORGE, Pa. — PJM provided more details last week on the April 21-22 transmission outage that resulted in the dispatch of demand response in the Erie area.

PJM’s Joe Ciabattoni told the Operating Committee that early on April 21, one of the three feeds into the Erie area, located in the PENELEC zone, was on a scheduled outage when a circuit breaker failed, taking one of the remaining paths out of service.

“That resulted in severe low voltage in a load pocket of about 200 MW,” he said. “If we had lost a third feed in the area, we would have lost that load pocket.” Ciabattoni noted at last week’s Market Implementation Committee meeting, where the matter also was discussed, that there always are voltage concerns in that area when there are planned or unplanned outages, and that an upgrade is included in next year’s Regional Transmission Expansion Plan.

When a workaround to bypass the breaker did not come to pass, PJM issued a PENELEC zone-wide voluntary call for DR to alleviate some of the voltage violations and implemented a switching solution, he said, estimating the DR available that evening at 130 MW.

“Going through the midnight period, we lost some generation in the area, which further aggravated the situation,” Ciabattoni said, so a voluntary call for DR again was made the following morning, when an estimated 73 MW was available. Because the outage occurred during a non-compliance period, all of the response was voluntary.

A sub-zonal call for DR was not made, he told the MIC, because it would have required a prior-day’s notice.

The event sparked the creation of two new closed-loop pricing interfaces in order to capture the DR dispatch in LMPs rather than in uplift — ERIE-PN, which is within the PENELEC zone, and the entire zone itself.

However, Stu Bresler, PJM vice president of market operations, told the MIC that PJM would not have let DR set prices for the full zone because the issue was isolated to the Erie area.

Black Start Service Undergoes Annual Revenue Recalculation

Black start generators are in the process of requesting changes to their annual revenue requirements, reflecting adjustments to net cost of new entry, operations and maintenance and fuel storage costs.

All combustion turbines and combined cycles, including black start units, are required to make changes to their accounting of maintenance expenses, said Thomas Hauske, senior lead engineer.

Unit owners and the Independent Market Monitor have until Thursday to agree on changes. PJM must accept or reject submitted values by May 27. The new rates take effect in June.

Load Management for 2015/2016 Presented

PJM expects about 8,250 MW of demand response for the 2015/16 delivery year.

Curtailment service providers registered 6,700 MW of pre-emergency DR and 1,550 MW of emergency DR as of April 30. Lead times break down as follows: Quick (30 minutes), 5,600 MW; Short (60 minutes), 350 MW; and Long (120 minutes), 2,300 MW. There are 6,000 MW of Limited DR (June- September); 2,100 MW of Extended Summer (May- October); and 150 MW of Annual DR. The figures will not be finalized until May 31.

The products are always called as a group unless they are out of season or they have been called too many times and PJM wants to save some Limited DR calls for later in the summer.

PJM has automated its dispatch of DR through its emergency procedure postings.

— Suzanne Herel

May 11, 2015June 15, 2023

PJM MIC Briefs

VALLEY FORGE, Pa. — The most likely dates for the 2018/19 Base Residual Auction to commence are Aug. 3 or Aug. 10, Jeff Bastian, manager of capacity market operations, told the Market Implementation Committee last week.

The timing will be determined by when the Federal Energy Regulatory Commission rules on PJM’s Capacity Performance proposal, which should be no later than June 9, assuming the commission acts 60 days from PJM’s April 10 response to FERC’s deficiency letter. (See PJM Responds to FERC Queries on Capacity Performance, Requests Approval.)

Bastian said PJM plans to announce a firm date for the auction, as well as deadlines for updates to market participant pre-auction submissions, shortly after FERC hands down its decision. PJM proposes using Aug. 3 if FERC rules on or before May 26, and Aug. 10 for an announcement after that date.

There are two scenarios, he said: Either the auction will be conducted according to PJM’s proposal, with or without FERC adjustments, or it will operate under the status quo.

Even if the new capacity product is denied and the auction runs under current rules, Bastian said, PJM believes it would be in everyone’s interest to utilize the 75 days allowed in its waiver to delay the auction, which generally is required to be held in May. (See FERC OKs PJM Request to Delay Capacity Auction.)

The Capacity Performance proposal (ER15-623) was conceived to increase reliability by implementing a “no excuses” policy that is expected to result in more incentives for over-performing participants and higher penalties for non-performers.

Bastian noted that an Aug. 3 auction date might necessitate an adjustment to the 2016/17 second incremental auction to avoid overlap.

PJM Member in Default, to be Terminated

PJM will seek to terminate the membership of Intergrid Mideast Group after it was declared in default for failing to honor collateral and payment obligations, CFO Suzanne Daugherty told the MIC.

Intergrid has accumulated three defaults within 12 months, and after the first one, its transaction rights were suspended. Now, PJM will be submitting a request with FERC to permanently cancel its membership, regardless of whether the defaults are rectified.

Intergrid, primarily a holder of financial transmission rights, paid its invoices through April 24. Its invoice due May 1 was fulfilled by the collateral it had posted with PJM, as will be the bill due May 8. That will leave $250,000 in remaining cash collateral.

PJM estimates that Intergrid may be liable for up to $2 million in charges on FTRs that expire May 31.

PJM plans to liquidate the FTR positions Intergrid also previously cleared in auctions for the 2015/16, 2016/17 and 2017/18 planning years. The positions for 2015/16 will be offered for sale during the FTR auction that opens this week.

The remaining positions will be offered for sale during the FTR auction that opens in early June.

PJM had no estimate for how much it will cost to liquidate the FTR positions.

Tariff Harmonization Group Offers First New Definition

The Tariff Harmonization Senior Task Force, formed in December to resolve inconsistencies and ambiguities in PJM’s governing documents, brought forward its first proposed change: the definition of PJM Net Assets.

“We thought it would be important to try and clarify what portion of PJM assets would be available for a third-party claim if one were made,” CFO Suzanne Daugherty told the committee. “You all don’t want everything in our financial statement available to a third-party claim.”

At any one time, she said, PJM could be holding roughly $1 billion on behalf of members, she said, but it’s not an asset.

The new definition specifies that PJM’s “Net Assets” will include those reflected in the RTO’s financial statements and not those for which it is acting as a temporary custodian on behalf of its members.

The group is prioritizing about 50 definitions and will next meet May 29.

New PJM Member Community to Debut

PJM will launch a new tool for interacting with members on May 18: the online PJM Member Community.

PJM’s Bill Walker said the new tool was conceived in response to members’ desire for a way to have their concerns acknowledged, track an issue or research topics themselves.

The service will provide the real-time status of a request, live chat, information on invoices and more.

Future enhancements are expected to allow members to initiate a change request, enable electronic signatures and integrate a mobile app.

The portal will be accessed through the “MyPJM” account ID.

— Suzanne Herel

May 11, 2015

PJM Debate over ‘Historic’ Capacity Rights Gets a Face: IMEA

By Suzanne Herel

VALLEY FORGE, Pa. — Months of debate over whether to create “historic” capacity rights for some unnamed load-serving entities in PJM got a face last week when a small contingent from the Illinois Municipal Electric Agency showed up at a meeting of the Market Implementation Committee to lobby for the changes.

The Tariff amendments would allow LSEs to use generation resources outside of their locational deliverability areas (LDAs) 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. (See Stakeholders Skeptical of PJM Proposal for ‘Historic’ Capacity Transfer Rights.)

Stu Bresler, PJM’s vice president of market operations, who had proposed the change, had not identified any potential beneficiaries, although it was clear one would be IMEA.

In January, IMEA failed to win approval from the Federal Energy Regulatory Commission to continue using capacity resources outside of the Commonwealth Edison LDA to meet its internal resource requirement in serving its Naperville, Ill., load. (See FERC Denies IMEA Request for Extended Waiver on Capacity Obligation.)

Last week, IMEA representatives came to Valley Forge state their case.

“We wanted to put a face on this and give you our answers,” said Troy Fodor, IMEA vice president and general counsel, who was joined by two colleagues.

“From our perspective, we’re not asking for a preference. We got the long-term transmission rights as part of going out and building brand-new plants,” he said. “We believe that since we have the firm long-term transmission rights that the transfer capability is ours. So, to the extent that it’s being taken and allocated out, and we’re getting a higher internal resource requirement, it feels like you’re taking our stuff.”

If it is a preference, he added, it’s one that IMEA feels it has justified by investing “a billion dollars” in plants to deliver load in ComEd.

In an interview after the meeting, Fodor explained the trip. “We need a solution,” he said. “If this process is going to fail, we have to start working at the next step. The reason we’re here is it looked like [talks] were going in the wrong direction.

“We have a good story,” he said. “We think we have a legitimate story.”

Bresler told the committee that historic capacity resources would not exceed the value at which they were initially established — and if the load should decrease, it would never go back up.

Market Monitor Joe Bowring, who has opposed Bresler’s proposal, said he continued to be concerned that the approach is too broad. “We are going to attempt to work with PJM and IMEA to see if there’s a way to come up with a more targeted approach,” he said.

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.

Bresler said the committee would see a first reading on proposed Tariff changes in June.

May 11, 2015

Arkansas PSC Chair Rips Republican ‘Just Say No’ Strategy on Carbon Plan

By Rich Heidorn Jr.

LITTLE ROCK, Ark. — Arkansas Public Service Commission Chairman Ted Thomas is no fan of the Environmental Protection Agency’s Clean Power Plan, but he’s perhaps even more critical of the “just say no” strategy of Senate Majority Leader Mitch McConnell and other congressional Republicans.

Thomas, a former Republican political consultant who served as budget director for former Gov. Mike Huckabee, said McConnell’s focus on coal job losses is a “narrow special interest” appeal. “That’s got to change if people in Osceola and Jonesboro are going to be protected,” he said in a passionate keynote speech to an audience of about 70 at the Gulf Coast Power Association’s SPP briefing last week.

Under EPA’s proposed rule, low-income Arkansas would be forced to reduce its carbon emissions by 44% from 2012 levels, the seventh-largest reduction of any state.

Thomas said EPA’s modeling failed to include stranded costs from premature generation plant retirements.

Devastating Hit

“If you’re a big company like Entergy, you can shift a few plants around, use your portfolio. A 10% or 15% [rate increase], it’s a lot of money — we don’t like that — but it might not end the world,” Thomas said.

“But if you’re in Jonesboro, Ark. — who’s paying for a coal plant that was built in 2010 and it gets retired and you have to pay for it for 35 years and get nothing while you also have to pay for an alternative source of electricity — your face gets ripped off.

“It’s not a small hit. It’s a devastating hit to a small town in the delta which is finally just seeing some good things happen [economically].”

Thomas said Republican congressional leaders made a mistake in supporting legislation by House Energy and Power subcommittee chairman Ed Whitfield (R-Ky.) and Sen. Rob Portman (R-Ohio) that would allow states to delay or opt out of compliance.

Thomas said the strategy failed because it did not gain the Democratic support needed to override a veto.

Instead, he said, Republicans should propose a bill limiting rate increases resulting from EPA’s final rule to 10% or 20% — legislation he believes many Democrats would be forced to support.

“Do you want to be the guy who votes against a 20% rate cap so some shark can make a commercial about [how] you thought it was OK that [constituents’] rates went up 20%? Nope.”

Thomas said that would force Democratic supporters of the EPA rule to pressure the agency on its cost.

EPA Administrator Gina McCarthy is “probably not going to pay attention to me. But she has to pay attention to her political allies,” Thomas said. “And until they feel pressure, they’re not going to come eyeball to eyeball with cost. The time to act is now while they’re still doing the rule. When you have the rule, it’s too late to change it.

“That’s the play that should be made when you do what politicians do: look at polls. Why they’re missing it is beyond me and beyond frustrating.”

Building the Ark

During a panel discussion later, Curtis Warner, director of compliance and support for the Arkansas Electric Cooperative Corp. (AECC), echoed Thomas’s concerns.

AECC expects it will have to reduce coal from 58% of electric generation to less than 9%, while natural gas generation rises to 73% from 30%. Warner said that would cost AECC ratepayers an average of $280 more per year — $450 more if natural gas prices increase by $1/MMBtu.

Lanny Nickell, SPP’s vice president of engineering, who also participated in the panel, noted that most of the generator retirements projected as a result of the rule are along the SPP-MISO seam. “That’s exactly where we’re not doing a good job of building transmission infrastructure,” he said.

Nickell likened himself to Noah. “Help us build the ark … the [transmission] infrastructure that we need,” he said. “The technical answer is not the most difficult part of this. It’s the political willpower that has to happen first.” (See SPP: $45/ton Adder, Wind, Gas Meets EPA Carbon Rule.)

David Farnsworth, senior associate for the Regulatory Assistance Project, also called for engagement. “The worst form of planning is just saying no,” he said.

May 11, 2015June 15, 2023

SPP Trying to ‘Balance the Risk’ on Gas-Electric Schedules

By Rich Heidorn Jr.

LITTLE ROCK, Ark. — The Federal Energy Regulatory Commission’s April 16 decision not to change the start of the gas day is forcing SPP to make an uncomfortable choice between risks, stakeholders said last week.

spp — From left to right: Amber Metzker, Xcel Energy; Chris Hendrix, Wal-Mart; and Richard Dillon, SPP.

FERC moved the timely nomination cycle deadline for scheduling gas transportation from 11:30 a.m. to 1 p.m. CT and added a third intraday nomination cycle. But, in the face of gas industry opposition, it declined to move the start of the gas day to 4 a.m. CT from 9 a.m. CT (RM14-2). (See FERC Approves Final Rule on Gas-Electric Coordination.)

“The electric industry wanted the gas industry to move their timelines and the gas industry said, ‘We were first; we don’t want to move, you move,’” summed up Tony Delacluyse, director of Power Costs Inc., during a discussion at the Gulf Coast Power Association’s SPP briefing. “And FERC did something they always do, they kind of picked something in the middle.”

FERC required each ISO and RTO to revise its day-ahead market timeline to coordinate with the pipeline scheduling changes or show why changes shouldn’t be implemented.

Richard Dillon, SPP director of market design, said SPP and other RTOs are considering moving the close of their electric markets to 8 a.m. CT — but with misgivings.

The current schedules make it impossible to clear the electric market in the time between when next-day gas prices are posted at about 9 a.m. CT and the current 11:30 a.m. timely nomination cycle deadline, Dillon said. The additional 90 minutes to the later nomination deadline makes it “a little more feasible,” Dillon said.

“We’re trying to figure out how to balance the risk. If I close the nominations for the electric market at 8 a.m. then I do not know tomorrow’s gas price,” Dillon explained. “But I have to close it at 8 a.m. to make the 1 p.m. nomination for the gas market. So there’s a lot of debate going on not just here but at the other RTOs about what’s the right balance of risk.”

“It’s definitely something that the membership is split on,” agreed Amber Metzker, manager of market operations for Xcel Energy.

Moving the close of the electric market to 8 a.m. would mean losing “certainty on price, certainty on transmission outages and all those things that go into the market clearing engine,” she said.

The benefit of such a change? Knowing how much gas you need to buy, Metzker said. “Right now the quantity of gas you’re buying is unknown because of the fact that the market is clearing after the fact of you submitting your offers in the day-ahead [market].”

Dillon said there was likely to be only limited coordination among RTOs regarding energy market schedules. (See PJM Considering Change to Day-Ahead Deadlines in Response to FERC Gas Schedule Order.)

“Right now New York’s not coordinating with anyone else’s timeline. New England is different than New York and PJM. I do not believe ERCOT is going to change, which means there wouldn’t be coordination there,” he said. “Some parties would say ‘Oh, that doesn’t matter.’ Well we have entities that actually have switchable generation. So they make a decision as to, ‘Am I going to be in ERCOT or SPP?’”

Dillon said SPP’s Gas-Electric Coordination Task Force and its Market Working Group will discuss the options and make recommendations.

May 11, 2015

SPP Issues RFP for 115-kV Transmission Project

SPP last week issued its first competitive transmission solicitation, inviting developers to bid on construction of a 21-mile 115-kV line between North Liberal and Walkemeyer in southwestern Kansas.

The SPP Board of Directors approved staff’s recommendation that it authorize construction of the project on April 28.

The board originally approved the project in January but asked staff to evaluate an alternative proposed by Sunflower Electric Power that would have delayed the line by relying on operating guides for Sunflower’s 76-MW Cimarron River Station to provide relief from thermal or voltage violations. (See Walkemeyer Transmission Projects Wins SPP OK.)

The request for proposals (SPP-RFP-00001) was sent May 5 to transmission developers that had cleared the RTO’s qualification process.

It is SPP’s first competitive solicitation under the Federal Energy Regulatory Commission’s Order 1000, which removed federal rights of first refusal for incumbent transmission owners. An “industry expert panel” will review, rank and score proposals received.

May 11, 2015June 15, 2023

PJM PC Briefs

VALLEY FORGE, Pa. — Despite a fee structure designed to encourage early submissions, PJM continues to receive too many interconnection requests late in the queue. As a result, planners introduced a problem statement and issue charge at the Planning Committee last week to find a better solution.

Planners proposed a new task force whose key assignment would be to “remove ineffective methods and identify new methods to incentivize new service customers to enter the queue earlier,” according to the issue charge.

“We’re of a mind that some of the rules need to be stripped out and replaced with something else,” said Steve Herling, PJM’s vice president of planning. “If it doesn’t serve a purpose, then maybe we strip that out, but it has to be replaced with something to incentivize.

“Maybe if you come in late and you’re deficient, you get first in line in the next queue,” Herling said. “If it’s time to start and you’re not on the boat, you wait for the next one.”

Herling said the problem statement would be returned to the committee next month for refinement.

Planners told the PC in January that they would be seeking stakeholder input on how to incent interconnection customers to submit their requests earlier. (See PJM to Try Again to Speed Interconnection Filings.)

Under the current structure, the deposit for applications filed in the first four months is $10,000; for the fifth month it is $20,000; and for the last month, $30,000. Nevertheless, about half of all queue submittals are filed in the last month, and about one-third in the final day of the window, creating a workflow crunch for planners.

Could Planning Upgrades Help Mitigate Uplift?

The PC began work on an assignment from the Markets and Reliability Committee to consider uplift among the problems to be addressed by grid upgrades under the Regional Transmission Expansion Plan.

Since July 2013, the MRC’s Energy Market Uplift Senior Task Force has been studying ways to reduce out-of-market make-whole payments, such as those for generators usually needed only for voltage support. So far this year, PJM has accrued $193 million in uplift charges, including $105 million in February alone.

“Are there [transmission] upgrades that might be more cost effective than running the generation that we’re currently operating?” asked Adam Keech, senior director of market operations.

Herling encouraged stakeholders to think about how to identify problems. He said the PC would conduct more substantive discussions at the next meeting.

PAR Charter Not Ready for Endorsement

The PC postponed a vote on the charter for a group charged with considering phase angle regulator transmission injection and withdrawal rights after a stakeholder complained that it had been posted too late under PJM rules.

The group will consider whether and how PARs can participate in the market and receive injection and withdrawal rights at PJM’s border, PJM’s Aaron Berner said.

The group will meet next on Thursday and is continuing to look for stakeholders interested in participating. So far, he said, about 20 have expressed interest.

— Suzanne Herel

May 11, 2015

Ameren Would Make Refunds Under Proposed Deal

By Chris O’Malley

Federal regulators last week said they support a settlement under which Ameren Illinois would refund $7.1 million to resolve a dispute over its purchase of Central Illinois Light Co. in 2003 and Illinois Power in 2004.

The settlement was filed April 14 by Ameren and a customer group consisting of the Illinois Municipal Electric Agency, Prairie Power Inc., Southern Illinois Power Cooperative and Wabash Valley Power Association. Federal Energy Regulatory Commission trial staff filed initial comments in support of the settlement on May 4 (AC11-46).

At the heart of the case is how Ameren Illinois accounted for goodwill in connection with the acquisition of the two Illinois utilities when it conducted a corporate reorganization in 2010.

As part of the reorganization, $197 million of goodwill that had been on Central Illinois’ books and $214 million of Illinois Power goodwill were transferred to Ameren Illinois.

In July 2012, FERC determined that Ameren Illinois and its predecessors had inappropriately included the $411 million in their common equity. The inflated rate base resulted in excess collections from ratepayers.

FERC also said the improper inclusion of goodwill in equity caused excessive collections under Allowance for Funds Used During Construction.

In a 2012 refund report required by FERC, Ameren contended it did not owe a refund. Even after removing goodwill from its capital structure, the company said, it was owed $19.7 million, plus $3 million in interest, because it had failed to include the cost of debt redemptions in Ameren and Illinois Power’s annual transmission revenue requirements from 2005 to 2012. FERC rejected Ameren’s claim in 2013, saying its proposed adjustments went beyond the scope of its July 2012 order.

The proposed $7.1 million refund would be paid to network integration transmission service customers for the period from June 1, 2005, through Dec. 31, 2014. The amount will be reduced by $2.1 million if a refund is ordered in a separate docket over Ameren’s booking of income tax overpayments (FA13-1).

If the settlement is approved by FERC, Ameren would also have to make adjustments to its common equity for Attachment O, removing $291.8 million for 2013 and $292.2 million for 2014.

May 11, 2015June 15, 2023

Former Soviet Spy Worked Undetected at NYISO, ConEd, NRG

By William Opalka

A former Soviet spy who lived in the United States for more than 35 years under an assumed identity has been working since 2011 as director of software development for NYISO but never had access to any sensitive data or operations, officials said.

The power grid operator responded to a CBS “60 Minutes” report that aired Sunday, in which “Jack Barsky” revealed his Cold War past, when he posed as an American in the 1970s and 80s in the hopes of gaining access to high ranking government officials.

Born Albrecht Dieterich in East Germany, he was recruited by the KGB as a student. He assumed the identity of Jack Barsky after Soviet agents provided him the birth certificate of an American boy who died at age 10.

Barsky told CBS he was directed to infiltrate the office of Zbigniew Brzezinski, President Jimmy Carter’s national security adviser from 1977-1981 but never got close to the official. He said his biggest coup was providing Soviets enterprise software designed by an insurance company for which he worked.

Barsky, who lives northeast of NYISO headquarters in Rensselaer, was placed on administrative leave recently when he told the ISO he was going to be the subject of a “60 Minutes” report.

According to his LinkedIn profile, Barsky came to NYISO after serving as chief information officer for NRG Energy from 2006 to 2010 and ConEdison Solutions from 2002 to 2006. The companies confirmed his employment to Capital New York.

“According to the story on ‘60 Minutes,’ Mr. Barsky appears to have had regular contact with the FBI over a period of many years that was not publicly disclosed. The FBI generally informs a company such as the NYISO of any potential cyber security threat of which it is aware. We have a long standing and productive relationship with the FBI and at no time did the FBI indicate that this employee posed a threat,” NYISO spokesman David C. Flanagan said.

“Out of an abundance of caution, we have conducted internal forensic reviews of physical and computer records and have not discovered any security threats or any indication that the employee engaged in improper behavior. The employee did not have direct access to grid operations or energy market systems that would enable manipulation of software. Further, the individual did not have physical access to our control rooms.”

Flanagan said NYISO has hired an outside firm to “to conduct a separate analysis to confirm our findings.”

Flanagan would not say if the recent departures of two NYISO executives — Jennifer Chatt, vice president for human resources, and Tom Rumsey, senior vice president of external affairs — were related to the Barsky revelation. Rumsey’s departure came just weeks after he received a promotion announced in January. (See NYISO CEO Stephen Whitley to Retire in 2016; Dewey, Rumsey Promoted.)

According to the “60 Minutes” report, Barsky was discovered in 1997 by the FBI, when he was working as a computer programmer in New Jersey. His last name had appeared in materials provided to the government by a KGB defector in 1992.

Barsky was never arrested or charged, as the FBI determined he would be of no value in jail; he was more useful living freely as he was debriefed about KGB operations.

Barsky had been ordered back to Germany in 1988 when the Soviets told him his cover had been blown, but he refused out of devotion to his American child. Under the threat of death, Barsky told “60 Minutes,” he concocted a story that he was suffering from AIDS and could only be treated in the U.S. The Soviets left him alone and he continued to live and work undetected.

Barsky, 70, told the Albany Times-Union that he is writing a book about his life.