Page 1558 – RTO Insider

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.

May 11, 2015June 15, 2023

PJM Market Monitor: Faulty Marginal Benefit Factor Harming Regulation

By Suzanne Herel

PJM’s regulation market is purchasing too much from fast-responding “RegD” resources, negatively affecting regulation and reliability, at the same time the RTO is incorrectly compensating those providers, the Independent Market Monitor said in a report presented last week to the Operating Committee.

Howard Haas of Monitoring Analytics said the root of the problem is an incorrectly defined marginal benefit factor that describes the relationship between RegD and traditional RegA resources.

While the MBF should be indicating when there is a diminishing return on the use of either resource, it has resulted in the over-procurement of RegD. In addition, it has led RegD resources to be alternately overpaid and underpaid. On average, Haas said, RegD resources have been undercompensated 46% from October 2012 through March using the current method.

“We never seem to be paying it the right amount,” Haas said. “It’s sending a strange signal to the market.”

PJM operators already had observed decreased market optimization during times when a large percentage of RegD is on the system. It provides more than 42% of response on average, shooting up as high as 70% during some events.

Last week, PJM presented the OC with a problem statement and issue charge to investigate the issue. The IMM wants to add to the inquiry an investigation into how the MBF is being defined and applied.

“If we follow it through, we’re going to correct more than one issue,” Haas said.

However, stakeholders agreed that the problem statement had been so substantially broadened since it was initially proposed that it was not ready for a vote. (See “Too Much of a Good Thing? PJM Concerned Fast Response Regulation Crowding Out Traditional Resources”, PJM Operating Committee Briefs.)

Instead, it will be reworked in a series of special OC meetings.

May 11, 2015June 15, 2023

ISO-NE: Plant Owner’s Responsibility to Flag Capacity Error

By William Opalka

ISO-NE said a power plant owner facing millions in what it says are mistaken capacity charges had plenty of time to correct the record, and that amending auction results after the fact would undermine the market.

GenOn Energy Management, a unit of NRG Energy, asked the Federal Energy Regulatory Commission last month for relief from what it called an “anomalous, illogical and patently unfair circumstance.”

GenOn said ISO-NE credited its Canal 2 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 that begins June 1. (See ISO-NE Error Could Cost GenOn Millions.)

GenOn said the RTO mistakenly underestimated the plant’s capacity and then 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.”

In an answer, ISO-NE said it was GenOn’s responsibility to correct the capacity values the RTO posted in October in preparation for the auction and that granting its request would set a dangerous precedent (EL15-57).

“The ISO is not in a position to discern the soundness of, or reasoning behind, the business-related actions (or inactions) of active and sophisticated market participants like GEM, much less to prevent them from making costly mistakes,” ISO-NE wrote.

“Granting the requested relief would undermine important principles of auction finality, eroding certainty and confidence in the markets and setting a possibly dangerous precedent,” ISO-NE continued. “Finally, the March 2015 ARA results are used as inputs to monthly bilateral arrangements and monthly reconfiguration auctions; these processes are already underway, and a change to the March 2015 ARA results could cause significant disruption.”

ISO-NE also said similar “corrections” could cause substantial harm to other parties. “If the March 2015 ARA had instead included more supply offers than demand bids, post hoc removal of the Canal 2 demand bid would have required a re-running of the auction and would have stripped some of the resources of the capacity supply obligations acquired in the first iteration.”

May 11, 2015June 15, 2023

MISO Company Q1 2015 Earnings Roundup: Week of May 12

Increased electric infrastructure investments in Illinois helped boost Ameren’s first-quarter profits by 12.4%.

The St. Louis-based utility reported net income of $108 million ($0.45/share) compared to $96 million ($0.40/share) last year. The earnings-per-share results were 7-10 cents higher than analyst estimates.

Revenue was $1.56 billion compared with $1.59 billion a year earlier.

Ameren said it benefited from increased electric delivery and transmission infrastructure investments and from an order by the Illinois Commerce Commission approving recovery of additional costs, which added 4 cents to earnings.

The regulatory climate in Missouri was less favorable, reflecting a reduction in allowable cost recovery for vegetation management, infrastructure investment costs and certain storm costs. The state also reduced return on equity to 9.53% from 9.8%.

Even so, Ameren held firm on its estimated full-year diluted earnings per share of $2.45 to $2.65.

Weather, Integrys Merger Costs Bruise Wisconsin Energy Q1 Earnings

Wisconsin Energy said first-quarter profit fell 6%, citing a warmer winter than a year ago and the costs related to its proposed acquisition of Integrys Energy.

The company reported net income of $195.8 million ($0.86/share) compared with $207.6 million ($0.91/share) in the first quarter of 2014. Revenues fell 18% to $1.39 billion. The company said 2014 revenues were higher due to the polar vortex and higher spot market prices for natural gas.

The Federal Energy Regulatory Commission and the Michigan Public Service Commission have already approved the Integrys deal. The Wisconsin Public Service Commission last month indicated it will likely approve the deal, to the chagrin of industrial and consumer groups that want Wisconsin Energy to promise specific rate savings to customers as a result of the $9.1 billion merger. Regulators in Illinois and Minnesota have yet to sign off on the deal.

Nuke Charge Slams Xcel Energy’s Q1 Profit

Xcel Energy’s first-quarter net income fell 41% from a year earlier on a milder winter and a $129 million pre-tax loss related to a 2013 upgrade of its Monticello nuclear plant.

The Minneapolis-based company reported a profit of $152 million ($0.30/share) compared with $261.2 million ($0.52/share) in the first quarter of 2014.

Profits took a 16 cents-per-share hit due to the loss stemming from the Monticello project. In 2013, Northern States Power-Minnesota completed a project to uprate the Monticello nuclear facility to 671 MW from 600 MW, at a cost of $748 million.

That was more than a 2008 estimate of $320 million. The Minnesota Public Utilities Commission completed a prudence review in March, determining that $333 million of the costs must be recovered over the life of the project.

Revenues of $2.96 billion were down 7.5% from the same quarter last year, largely on milder winter weather that reduced consumption.

Xcel reaffirmed full-year earnings per share of $2 to $2.15.

— Chris O’Malley

May 11, 2015

FERC Issues Request for Comments in UTC Uplift Docket; Ruling by October?

By Rich Heidorn Jr.

If the Federal Energy Regulatory Commission keeps its word, virtual traders in PJM should have clarity by the end of October on whether up-to-congestion transactions will be subject to additional charges.

In opening a section 206 docket on the issue last year, the commission said it would rule within five months after it receives comments following a technical conference.

The technical conference was held Jan. 7. On April 29, the commission issued the request for follow-up comments, which are due May 29 (EL14-37).

In September, FERC ordered the 206 proceeding to determine whether PJM is improperly treating UTCs differently than incremental offers (INCs) and decrement bids (DECs). While INCs and DECs are charged uplift and subject to the financial transmission rights forfeiture rule, UTCs are exempt from both.

UTC trading volumes collapsed after Sept. 8, the refund-effective date set by FERC for any uplift assessments. Some financial traders have discussed an interim fee on UTCs in an effort to encourage trading pending resolution of the case. (See Cool Response to Proposed 7-Cent Fee on Virtual Transactions.)

Among the questions on which FERC solicited comment were:

How should the injection/withdrawal points for the virtual transaction be identified?
Should the defined “worst case” node be limited to the market participant’s own transactions?
Should the FTR forfeiture rule collectively assess the net impact of a market participant’s entire portfolio of INCs, DECs and UTCs instead of the current rule, which assesses virtual transactions one at a time?
Should counter-flow FTRs and bids that relieve congestion remain exempt from FTR forfeiture rule calculations? Should financial transactions that improve day-ahead and real-time market price convergence be exempt from the forfeiture rule?
Should UTCs be assessed uplift?
Do UTCs impact unit commitment decisions?
Should market participants be allowed to net INC and DEC transactions for the purpose of uplift allocations?