Page 1563 – RTO Insider

June 24, 2014

FERC Splits over ROE

The Federal Energy Regulatory Commission unanimously agreed last week to change the way it calculates return on equity (ROE) rates for electric utilities, moving to a two-step process it has long used for natural gas and oil pipelines that incorporates long-term growth rates.

But the panel split 3-1 over its first application of the new formula, tentatively setting the ROE for New England transmission owners at three-quarters of the top of the “zone of reasonableness,” a departure from the prior practice that used the midpoint in the range.

The case resulted from a complaint filed in 2011 by New England state officials and others that challenged the New England TOs’ 11.14% base ROE as unreasonable. The commission’s ruling (EL11-66-001) sets the ROE at 10.57% for the New England TOs, which include Northeast Utilities, Central Maine Power Co., National Grid and NextEra.

(Although the commission chose a higher position within the range, the New England TOs’ ROE was reduced because the new formula reduced the top end of the zone.)

The commission also ordered hearing and settlement judge procedures in five pending challenges to electric utility ROEs, saying they should be resolved within the new framework. These include a December 2012 complaint that sought to reduce the New England TOs’ ROE to 8.7% (EL13-33) and cases involving Florida Power Corp.(EL12-39), Duke Energy Florida (EL13-63 & EL12-39) and Southwestern Public Service Co. (EL12-59 and EL13-78 & EL12-59).

FERC Staff, Consumers Rebuffed

In setting the ROE at the 75^th percentile of the zone of reasonableness, the commission majority sided with the TOs and rejected arguments by FERC trial staff and consumer representatives, who had argued for continuing the commission’s traditional use of the zone’s midpoint.

Acting Chair Cheryl LaFleur, a former executive vice president and acting CEO of National Grid, sided with the two Republican commissioners, Philip Moeller and Tony Clark, saying the change was justified because of the unusually low current interest rates.

Commissioner John Norris — a Democrat like LaFleur — issued a partial dissent, saying that while he agreed that the companies deserved an ROE increase, there was insufficient evidence to support setting the rate so high.

“This order tilts the balance too far,” Norris said in a statement during the commission’s public meeting. “They will clearly be celebrating in the corporate boardroom of Northeast Utilities today.”

New Formula

The order changes the methodology for electric utility ROEs from a one-step discounted cash flow (DCF) model to the same two-step DCF the commission has used for natural gas and oil pipeline ROEs. While the one-step methodology relies on only short-term growth rates, the two-step process includes short-term and long-term growth rate estimates.

The commission said the two-step process will produce a narrower zone of reasonableness because long-term growth rates are more stable than short-term growth rates and because the two-step methodology does not calculate a high-end and low-end cost of equity estimate for each company in the relevant proxy group.

The two-step methodology “is less likely to produce the anomalous results that can result from combining high and low dividend yields with high and low short-term projections of dividend growth to produce two estimates for each proxy company,” the commission said. “The end result is often a zone of reasonableness that is defined by two widely divergent growth rates that do not engender much confidence in the reliability of the estimates.”

The commission ordered a paper hearing to determine whether growth in gross domestic product should be the indicator for long-term growth rates, as it is in natural gas and oil pipeline proceedings. Using the GDP indicator, the commission tentatively set the zone of reasonableness as 7.03% to 11.74%.

The previous zone ranged from 7.3% to 13.1%. Thus, although the commission chose a higher position within the range, the reduced top end resulted in a decrease from the New England TOs’ previous ROE, which also included a post-hearing adder.

Clearing the Backlog

In announcing the ruling at last week’s commission meeting, LaFleur said that she had made acting on a backlog of ROE cases a high priority when she was appointed acting chair in November. “I established specific goals for addressing the ROE cases, including that any resolution would be fair to customers and investors, principled and sustainable, and represent a consensus of my colleagues. While we did not achieve unanimous agreement on all points, I believe that we have met these goals,” she said.

LaFleur said the grid’s shift from coal to natural gas and renewables “will require the construction of a significant amount of transmission in the coming years. I anticipate that this order, along with our recent compliance orders on Order No. 1000 will help provide some certainty to that process.”

Norris: `Troubling Precedent’

Norris praised LaFleur for pushing the commission to act on the ROE disputes, which he said “had been languishing too long.”

But he said the order sets a “troubling precedent” and may subject consumers to unjustly high rates in the future.

He said he would have ordered a paper hearing because there was insufficient evidence to support setting the rate at the 75^th percentile.

“Regrettably, today’s order tilts the balance in favor of the New England transmission owners without further recourse and fails to adequately give a voice to consumer interests,” he wrote in his dissent.

“Looking beyond today’s order, my broader concern is that the precedent established through this adjustment could become the new norm that would potentially ratchet up and lock in substantially higher ROEs in future cases. I am further troubled by today’s order in light of recent commission decisions on Order No. 1000 compliance filings that have served to protect incumbent transmission owners from competition in the development of new transmission. Simply put, not only will incumbent transmission owners be more insulated from competition, they will also be the primary beneficiaries of the new precedent established in this proceeding that could provide for substantially higher ROEs.”

Treasury Bond Update Eliminated

The commission’s order also ends its practice of using U.S. Treasury bond yields to make a final ROE adjustment, which reflect changes in capital market conditions after the close of the record in a rate hearing. Instead, the commission’s decision will be based on the latest financial data available in the hearing record.

The D.C. Circuit Court of Appeals had ordered the commission to revisit the issue in a ruling on a 2008 ROE case involving Southern California Edison Co. The court said FERC should consider evidence that U.S. Treasury bond yields and corporate bond yields might be inversely related. The commission acknowledged that “there is not necessarily a one-to-one correlation between U.S. Treasury bond yields and public utility returns on equity.”

June 24, 2014

PPL-Riverstone Spin-Off Shuffles GenCo Rankings

Will PPL shareholders be better off now that the company has decided to spin off its generation?

Wall Street seems far from convinced, with the company’s stock price virtually unchanged since the deal with investment firm Riverstone Holdings LLC was announced. (Though you would have earned a tidy 13.5% return had you bought when rumors of the spin-off began bubbling up in early February.)

But there’s no doubt the tax-free deal creating Talen Energy will shuffle the generator rankings. The new company will have more than 15,000 MW of generation, ranking fifth nationally in competitive generation (behind NRG, Exelon, Calpine and Next Era) and third among independent power producers.

Within PJM, it will rank sixth with more than 12,000 MW of generation, behind AEP, Exelon, Dominion, NRG and FirstEnergy. Its 1,883 MW in Texas will give it presence in the Electric Reliability Council of Texas (ERCOT). PPL said Talen anticipates needing to divest about 1,000 MW of generation to achieve regulatory approval, but it wouldn’t say what plants might be affected.

Meanwhile, Exelon and other integrated utilities are rumored to be considering PPL’s pure-play strategy. The rationale: By concentrating on regulated operations, utilities will be more attractive to shareholders seeking steady earnings and dividends, while more risk-tolerant investors can ride the highs and lows of merchant generation.

Welcoming Volatility

In announcing the deal, PPL Corp. CEO Bill Spence made repeated references to the volatility of the generation markets in PJM and ERCOT and said Talen would be poised to take advantage of it.

PPL, meanwhile, will be left with a “100% rate-regulated business model [that] provides earnings and dividend growth potential.” He said PPL expects “substantial” growth in the rate base in the coming years.

PPL shareholders will own 65% of Talen, with Riverstone holding 35%. The company will be listed on the New York Stock Exchange.

Coal and Natural Gas

Both Riverstone and PPL come with substantial coal generation — both about 40% of their portfolios. The company will also have a 40% share of natural gas, with 15% of its portfolio in nuclear and the remainder in oil (3%) and renewables (2%).

The combination, according to PPL Corp. CEO Bill Spence, will make Talen a “highly competitive player, operating very attractive assets, in the right regions” with “a significant proportion [of generation] with low or no carbon dioxide output.”

The new company will assume PPL Energy Supply’s 10,000 MW of generation, primarily in Pennsylvania, which includes its 90% stake in the Susquehanna nuclear generating station (pending approval by the Nuclear Regulatory Commission), 292 MW of hydro in Pennsylvania and 677 MW of coal-fired generation in Montana. It does not include 11 Montana hydro facilities, whose sale to NorthWestern Corp. was announced in 2013 and is nearing closing.

The Riverstone fleet includes three coal- and natural gas-fired plants in Maryland, five natural gas- or oil-fired plants in New Jersey, one natural gas plant in York, Pa., a natural gas-fired plant in Dartmouth, Mass., and five natural gas-fired plants in Texas. Combined, they produce 5,345 MW.

Not Included

Not included in the generation spinoff are the approximately 8,000 MW of generation PPL owns and operates in Kentucky. “The Kentucky generating plants are part of the rate bases of PPL’s Louisville Gas & Electric and Kentucky Utilities subsidiaries,” PPL spokesman George Lewis said Friday. “The Talen Energy transaction involves only merchant generating plants owned by PPL.”

The regulated delivery business in the United Kingdom – where PPL has 7.8 million electric customers – also will be unaffected by the transaction, Lewis said.

Lewis said Talen Energy headquarters “will be in Pennsylvania, but the specific location has not been chosen yet.” Marketing the generation will be done by PPL Energy’s existing marketing operation, he said.“Talen Energy will have an asset-focused energy marketing operation to get the greatest value for electricity generated by Talen Energy plants,” he said.

Layoffs Expected

Paul Farr, president of PPL Energy Supply, will become president and CEO of Talen at the closing of the deal. Jeremy McGuire, PPL’s vice president of strategic development, will be Talen’s chief financial officer.

“There will be job reductions across PPL as a result” of the transaction, he said. “The number of positions and the timing of the reductions will be determined during the transition process over the next nine to 12 months.”

Regulatory Approvals

Lewis said the partners anticipate completing the transaction by the middle of 2015. Approvals will be necessary from the Federal Energy Regulatory Commission, the Federal Trade Commission, the Department of Justice, the Nuclear Regulatory Commission and the Pennsylvania Public Utility Commission.

The NRC, which has to approve any transfer of Susquehanna’s operating license to the new company, will meet with PPL July 2 to discuss its plans. The meeting, from 10 a.m. to noon, will cover the new owner’s financial and technical qualifications, among other areas. Members of the public will be able to call in to the meeting to participate. The NRC approval process could take up to a year, an agency spokesman said.

June 24, 2014

Rebuffed by Courts, CPV Seeks FERC End-Around

Utilities in New Jersey and Maryland are fighting an attempt by a generation developer to enforce contracts that federal courts last year ruled invalid.

Competitive Power Ventures filed requests June 2 asking the Federal Energy Regulatory Commission to declare just and reasonable the contracts that would provide funding for CPV’s generating plants in Woodbridge, N.J., (ER14-2105) and Waldorf, Md. (ER14-2106).

CPV filed the requests with FERC on the same day that the Fourth Circuit Court of Appeals unanimously upheld a district court ruling throwing out the Maryland contracts (PPL EnergyPlus, LLC, et al. v. Nazarian, Civil Action No. MJG-12-1286). The court declared that the contracts violated FERC jurisdiction and were thus “illegal and unenforceable.”

CPV Woodbridge Construction (Source: Competitive Power Ventures)

CPV hopes to build a 661-MW combined cycle generator funded by 20-year “contracts for differences” with Baltimore Gas and Electric Co., Delmarva Power & Light Co. and Potomac Electric Power Co. The electric distribution companies (EDCs) were ordered to sign the contracts after CPV won a competitive solicitation by the Maryland Public Service Commission for construction of a new generating plant in the Southwest MAAC zone.

CPV also won a 2011 solicitation by the New Jersey Board of Public Utilities that resulted in 15-year “standard offer capacity agreements” (SOCA) with Rockland Electric Co., Public Service Electric and Gas Co., Jersey Central Power & Light Co. and Atlantic City Electric Co. tied to CPV’s 663-MW combined-cycle Woodbridge generation plant, now under construction.

Those contracts were struck down in October by the U.S. District Court in New Jersey (PPL EnergyPlus, LLC, et al. v. Hanna, Civil Action No. 11-0745). As in the Maryland case, the New Jersey contracts were ruled in violation of the Constitution’s Supremacy Clause and thus “void ab initio, invalid and unenforceable except for the termination provisions which any party may implement or defend.” The BPU appealed the ruling to the Third Circuit Court of Appeals.

The EDCs subject to the contracts filed protests on June 12 opposing CPV’s FERC filings. Also joining the protests were PPL, Calpine, Essential Power LLC and Lakewood Cogeneration LP. As a result of the court rulings, the protestors said, the contracts “do not exist.”

CPV’s “tactic of not only asking the commission to accept the purported `agreements’ for filing, but also to make a just and reasonable determination, is particularly curious and ill-advised in light of these preemption rulings,” the protestors wrote.

CPV Senior Vice President Braith Kelly said the company made the FERC filings to protect its interests in case it does not prevail on appeal. “If these are in fact FERC jurisdictional contracts that means FERC can rule on them,” he said in an interview.

CPV said the contracts do not threaten FERC’s jurisdiction, as the courts ruled, because they are “simply … financial settlements” based on capacity market prices and “do not require or in any way involve the delivery of capacity or energy to the EDCs.”

Contracts Explained

Under the Maryland contracts for differences, if CPV’s PJM energy and capacity revenues are less than the amount specified in the contracts, the EDCs will pay CPV the difference; if the revenues exceed the amount specified in the contracts, CPV would pay the EDCs the difference.

The New Jersey contracts are similar. CPV will receive the benchmark price it bid into the state solicitation minus revenues it receives through PJM’s capacity market. If the plant’s capacity market revenue is less than the benchmark price, the EDCs will pay CPV the difference; if capacity revenues exceed the benchmark, CPV pays the EDCs.

CPV said that while it appeals the court rulings, it was submitting the contracts to FERC “solely for the limited purpose of requesting that the commission review and determine that the rates in the SOCAs are just and reasonable and otherwise comport with the standards for rates in jurisdictional contracts under FPA Section 205.”

Other State Solicitations

CPV says the state initiatives that resulted in the contracts were “no different than the solicitations routinely mandated by state commissions for the procurement of energy to serve those loads that have not selected competitive suppliers,” called basic generation service (BGS) in New Jersey and standard offer service (SOS) in Maryland.

A FERC ruling that the CPV contracts are not just and reasonable and cannot be enforced “would call into question the reasonableness of rates charged by any jurisdictional seller participating in the BGS or in any similar state-mandated solicitations,” CPV wrote in support of the New Jersey contracts.

The fact that the EDCs entered into the contracts “under protest” is irrelevant, CPV said, because the state’s solicitation “resulted in no less an arms-length transaction than the BGS solicitations where the NJ BPU also mandated the procurement of electricity on terms it required.”

Because the contracts resulted from a competitive process, CPV said they meet the Allegheny and Edgar standards the commission applies in evaluating whether contracts awarded by EDCs to affiliates are just and reasonable.

FERC Position in Dispute

The protestors pointed to the Department of Justice’s amicus brief in the New Jersey case, which said the state-ordered contracts have a “price-suppressing and distortive effect on PJM’s wholesale capacity market prices.”

Kelly acknowledged FERC was a signatory to Justice’s brief. But he said the commission’s true position was spelled out in its approval of PJM’s revised minimum offer price rule (“MOPR 2”), which was designed to prevent state-supported generation from undercutting auction prices.

CPV said its New Jersey generator, which is about 20% complete, offered and cleared in each of the three base capacity auctions since 2012 under MOPR. The company did not disclose whether the Maryland project, for which it is attempting to secure financing, had cleared.

“In adopting MOPR 2 and doing away with the state exemption and defending that in the 3rd Circuit, FERC stated very clearly that these projects were economic,” Kelly said. “The change in the MOPR was designed to ensure these projects – these specific projects – did not adversely affect the market.”

A BPU spokesman declined to comment on the impact of a potential FERC decision on the appellate court case.

June 18, 2014

UPDATE: LaFleur to Remain Acting FERC Chair for up to 1 Year in Senate Deal with White House; Bay Wins Floor Vote

WASHINGTON — Cheryl LaFleur will likely remain acting chair of the Federal Energy Regulatory Commission for another year under a deal with the White House that won a Senate floor vote for Norman Bay.

A Senate panel voted June 18 to approve Bay’s appointment to FERC in a deal that will keep LaFleur in her leadership role for nine months after Bay’s confirmation by the full Senate.

The Senate Energy and Natural Resources Committee voted 13-9 to confirm Bay and 21-1 to grant LaFleur a second five-year term. With a floor vote not expected until September, LaFleur could remain in the top spot until June 2015.

LaFleur had sailed through her confirmation hearing May 20 while Bay was forced to defend his limited policy experience and his running of the commission’s enforcement division. The Department of Energy Organization Act gives the Senate authority to confirm members of FERC but gives it no say over which one of the commissioners is appointed chair by the president.

The president’s concession was enough to win the support of West Virginia Democrat Joe Manchin today but not that of ranking member Lisa Murkowski (R-Alaska) and most of her Republican colleagues. Murkowski said she wanted the president to remove the “acting” designation from LaFleur’s chairmanship so that she had full authority to act in a leadership role.

“I have not been given the assurance that she would be given the full authority as the chairman,” Murkowski said before casting her “no” vote.

Experience Questioned

Earlier in the hearing, Murkowski noted that lights in the Capitol were dimmed to conserve energy and said “there might be rolling brownouts this afternoon” as temperatures hit the 90s. She also cited FERC’s role in ensuring the grid’s reliability in the face of increasing environmental regulations on fossil fuel-fired generators.

“We need the best of the best running the commission,” Murkowski said.

While praising Bay as “a learned man,” she said the FERC chairmanship was not the place for “on-the-job training.”

Bay, who has served as director of FERC’s Office of Enforcement since 2009, is a former federal prosecutor and law school professor. Unlike most FERC commissioners in the last decade, he has never served as a state utility regulator.

Of the 15 FERC commissioners who have served since 2000, 10 served as commissioners or staffers at state regulatory agencies prior to their appointments. Four of the others worked in energy-related posts in state or federal legislative committees or executive agencies; one was a former utility executive.

The last five chairmen served a median of 30 months before becoming chair. Only one, Patrick H. Wood III, served less than a year on the panel before his promotion.

Murkowski and others also raised the issue of gender politics, questioning why Obama announced his intention to appoint the less experienced Bay directly into the chairmanship, “particularly when we have a woman … as the acting head of this commission. By all reports [LaFleur’s] been doing a good job,” Murkowski said. LaFleur is the only woman on the commission.

Among those who had expressed concern over Bay’s limited energy policy experience was Manchin, who helped sink the bid of Obama’s previous nominee, former Colorado regulator Ron Binz.

That sparked a flurry of negotiations over the last several days among the White House, Murkowski and Energy committee Chair Mary Landrieu (D-La.), which resulted in the president’s concession not to appoint Bay chairman immediately.

The lone vote against LaFleur apparently came from Vermont Sen. Bernie Sanders, an independent who caucuses with the Democrats. Sanders said he was not opposed to LaFleur’s second term but was protesting the delay in Bay’s ascension. “I think Mr. Bay would be an outstanding chair,” he said.

The committee’s vote sends the Bay and LaFleur nominations to the full Senate, where Bay has the backing of Senate Majority Leader Harry Reid (D-Nev.). In an interview with The Wall Street Journal June 8, Reid said bluntly, “I don’t want [LaFleur] as chair.”

Reid told the Journal he was concerned LaFleur would not adequately enforce market manipulation rules or support building transmission for renewable energy. Reid also said he feared LaFleur would undo initiatives of former chair Jon Wellinghoff, a Nevadan allied with Reid who retired last year.

“This is not the outcome Sen. Reid would have preferred but he accepts the compromise negotiated by Sen. Landrieu and he will move forward with confirming the nominees,” a Reid spokeswoman told The National Journal after the vote.

Enforcement Criticism

The criticism over Bay’s management of FERC’s Office of Enforcement was sparked by members of the energy bar, led by former FERC general counsel William Scherman. In a 49-page article in the Energy Law Journal, Scherman accused Bay of driving Wall Street banks out of energy trading with heavy-handed enforcement tactics. Several senators continued to probe the issue in post-hearing questions to Bay and LaFleur.

In her answers, LaFleur acknowledged differing with Bay and her fellow commissioners on procedural matters regarding seven investigations, including four in which the subjects were represented by Scherman. While LaFleur characterized the disagreements as “procedural” and not substantive, the disclosures did lend some credibility to Scherman’s critique.

June 16, 2014

PSEG Wins $300M Artificial Island Project

PJM planners today recommended Public Service Electric and Gas be awarded the contract to fix the Artificial Island stability problem with a new 500-kV line from Hope Creek, N.J. to Red Lion, Del. at a cost of about $300 million.

The planners recommended PSE&G construct the 18-mile line and upgrades to its Hope Creek 500-kV station. Pepco Holdings Inc. will upgrade its Red Lion 500-kV station at the other end of the line under the recommendation.

The stability fix for Artificial Island — home of the Salem and Hope Creek nuclear plants — is PJM’s first competitive transmission project under the Federal Energy Regulatory Commission’s Order 1000.

The competition attracted 26 proposals from five utilities and three independent developers, led by PSE&G with 14 alternatives. In May, planners identified a shortlist of 10 proposals, including the 500-kV proposal by PSE&G and a similar project by Dominion Virginia Power.

The two projects — which had been in the middle of the pack in cost and did poorly in their original forms in an analysis of risk factors and technical concerns — had their standings improve dramatically when PJM reevaluated them after eliminating a second tie line between the two nuclear plants.

The revised Dominion and PSE&G proposals got top scores in the analysis and also saw their costs reduced by $34 million and $43 million, respectively. PJM estimated either project would cost between $211 million and $256 million, the same range it assigned to a 230-kV proposal by LS Power that had been the cheapest proposal prior to the change. (See Dominion, PSE&G Proposals Gain in Artificial Island Race.)

The estimates do not include an additional $80 million for a static VAR compensator (SVC), which PJM added to all of the proposals. In total, the winning project is expected to cost $291 million to $337 million.

Paul McGlynn, general manager of system planning, said that planners chose the 500-kV proposal because it provided greater transmission capacity than the 230-kV alternatives and would use an existing Delaware River crossing rather than a new southern crossing employed by the 230-kV proposals. PJM said the river crossing “represents the greatest component of schedule risk” for all proposals.

McGlynn said planners chose PSE&G over Dominion because PSE&G is a party to the Lower Delaware Valley (LDV) Transmission Service Agreement, which controls an existing 500-kV right of way in New Jersey that the new line will largely parallel. Although PSE&G will need expand the right of way for 8.5 miles, Dominion would have needed to acquire the right of way for the entire route, PJM said.

The planners will recommend the Board of Managers include the project in the Regional Transmission Expansion Plan at the board’s July 22 meeting. McGlynn said PJM will accept comments on the recommendation through July 16.

The winning project is a modification of PSE&G’s proposal (#7K), which was originally proposed at a cost of $1.066 billion. PJM planners reduced the cost by eliminating a 500-kV line between New Freedom and Deans, making changes to breaker configurations and eliminating the second tie line between the two nuclear plants. Eliminating the second tie line also eliminated the need for the 500-kV line to cross another 500-kV line, which would have created a risk of a multiple facility trip.

The SVC will be added at PSE&G’s New Freedom switching station. PJM added the SVC despite opposition from PSEG Nuclear LLC, the operator of the nuclear plants, which said SVCs have never been used to correct “transient angular stability.” PSEG Nuclear said the SVC would pose “unknown and potentially challenging regulatory risks,” including an “in-depth review” by the Nuclear Regulatory Commission.” (See Contestants Make Last Pitch for Artificial Island Prize.)

PJM acknowledged that the selected route faces land-permitting challenges because it will cross the Supawna Meadows National Wildlife Refuge, the Alloway Creek Watershed Wetland Restoration Site and the Abbotts Meadow and Mad Horse Creek Wildlife Management Areas. The New Jersey Board of Public Utilities said PJM’s analysis of the 500-kV option underestimated likely public opposition.

Sharon Segner, vice president at LS Power, said afterward that she was “profoundly disappointed” by PJM’s decision and predicted PSEG will be unable to win approvals to build the line across the New Jersey wetlands and wildlife areas.

McGlynn said the project’s cost allocation will be “very similar” to the allocation outlined in May, which spread the cost among two dozen transmission zones and merchants. The Jersey Central Power & Light zone would be responsible for about 27% of the project, with the Atlantic City Electric zone picking up almost 20%. No other zone was as high as 8%.

FERC Order 1000 eliminated incumbent utilities’ federal right of first refusal (ROFR) on new transmission projects, opening the business to competition from independent transmission developers.

Others submitting proposals in addition to PSE&G, Dominion and LS Power were Transource Energy, a partnership between American Electric Power and Great Plains Energy (owner of Kansas City Power & Light Co.); FirstEnergy Corp.; Atlantic Wind Connection; and a partnership between Pepco Holdings Inc. and Exelon Corp.

June 10, 2014

Planning Assumptions Debunked by Winter Outage Study

PJM will likely change its planning assumptions based on an analysis that found a strong correlation between wind chill indices and generator outages.

“Planning studies currently assume that forced outages are random and occur at a constant rate throughout the four seasons,” PJM’s Tom Falin told the Planning Committee last week. However, the analysis of generation outages from winters 2007/08 through 2012/13 found that the lower the wind chill, the more gas-fired capacity is lost to forced outages, including gas curtailments.

“We used to [consider] all unit forced outage rates as independent of each other, but we saw in January that they clearly are not. If you can’t get gas for one unit, you can’t get it for all units,” Falin said.

The analysis identified 9,244 MW of “chronically curtailed” gas plants — those that were curtailed an average of at least 12 hours per year. Jerry Bell of PJM explained that 2013/14 data was left out of the study because “we didn’t want to poison [the data] with the most recent winter.”

Under a worst-case scenario, which assumes the loss of all existing gas plants that were curtailed at least once over the last six winters and all “at-risk” future units (those likely to be “chronically curtailed” based on their pipeline supply), PJM could be forced to operate without 42,700 MW of gas capacity.

The analysis showed variability across zones. The ComEd zone, for example, had more than 2,600 MW of “chronically curtailed” gas generation while the JCPL zone had just 41 MW.

PJM officials said they will likely change their planning assumptions to recognize the increased risk of gas outages during extreme cold. The analysis may also result in new rules regarding the firmness of winter fuel supplies and calculation of winter Capacity Emergency Transfer Objectives and Capacity Emergency Transfer Limits.

“Clearly, the range of potential solutions is different for next winter than it is for 2019/20,” Vice President of Planning Steve Herling said. “Everything is on the table right now.”

Carl Johnson, of the PJM Public Power Coalition, said it may be necessary to develop both RTO-wide and zonal solutions. “In addition to studying why units were out, we should study why units weren’t out,” he said.

June 10, 2014

LaFleur Parts with Bay on Enforcement Procedures

To win confirmation as Federal Energy Regulatory Commission chair, Norman Bay will have to overcome both questions about his energy policy experience and criticism of the agency’s enforcement practices. His case wasn’t helped last week by the responses Acting Chair Cheryl LaFleur filed in response to questions from the Senate Energy and Natural Resources Committee.

LaFleur made clear she hasn’t always agreed with Bay or her fellow commissioners on FERC enforcement policy, detailing seven cases in which she issued separate concurrences or dissented from the majority. In four of the cases, the subjects were represented by former FERC general counsel William Scherman, who co-authored an Energy Law Journal article last month accusing FERC of heavy-handed enforcement tactics.

While LaFleur characterized the disagreements as “procedural” and not substantive, the disclosures could lend credence to Scherman’s criticism of the Office of Enforcement, which Bay has led since 2009.

In three cases, LaFleur said she disagreed with the way the commission applied its penalty guidelines, which she said “had the effect of double-counting the duration of the violations and unduly increasing the amount of the civil penalty range.” Commissioner John Norris joined her dissent in one of the cases.

She also dissented from a commission decision rejecting Barclays’ motion to quash a subpoena. The motion came after Bay’s office had issued an order to show cause, accusing the bank of market manipulation. Barclays had chosen to forego a hearing before an administrative law judge and instead have the commission assess a civil penalty for the alleged misconduct.

“In my view, the statutory directive that the commission `promptly assess’ a civil penalty could not be reconciled with further investigation into the conduct that was detailed in the order to show cause,” LaFleur wrote.

LaFleur said she also split with Bay and other commissioners in a non-public order related to the timing of an investigation subject’s access to deposition transcripts. “The commission’s regulations state that even if good cause exists to deny witnesses a copy of his or her deposition transcript, `[i]n any event, any witness or his counsel, upon proper identification, shall have the right to inspect the official transcript of the witness’ own testimony,’” LaFleur wrote. “I believe this regulation does not permit a delay in providing access to transcripts.”

Scherman had alleged that FERC “denied witnesses the right to procure copies of, or to inspect, the official transcripts of their own depositions” in “a number of nonpublic cases.”

Finally, LaFleur dissented with the commission’s decision to suspend J.P. Morgan Energy Venture’s market-based rate authority in response to the company’s alleged misrepresentations during a market manipulation investigation.

“I viewed such a suspension as inconsistent with the commission’s market-based rate regulations,” she wrote. “Instead, I believe that any misrepresentations should have been addressed as part of the ongoing investigation into J.P. Morgan’s bidding activities, either as separate counts of obstruction, or as aggravating circumstances factoring into the determination of a civil penalty.”

June 10, 2014

PJM Balks at Lowering QTU Credit Requirement

PJM objected last week to a transmission developer’s efforts to reduce credit requirements on Qualifying Transmission Upgrades (QTUs), saying the RTO lacks authority to compel construction of the projects.

QTUs are small transmission projects that can be offered into capacity auctions to relieve transmission constraints in locational deliverability areas (LDAs). Developer H-P Energy Resources LLC won stakeholders’ OK in February to reconsider the current credit requirements, which it contends are out of proportion to the costs and risks of such projects. (See Members OK Review of Qualifying Transmission Upgrades Credit Rules.)

Janine Durand, attorney for the developer, told the Market Implementation Committee last week that a $7 million reconductoring would require posting credit of about $32.5 million. Durand proposed a change that would limit the credit to 100% of the upgrade cost.

“This is unreasonable for Qualifying Transmission Upgrades and presents a barrier for entry for these types of projects,” she said, adding that the majority of QTUs “move ahead quickly” and are relatively low-risk compared with generation projects that offer into capacity auctions.

However, Durand and PJM disagreed over how the RTO could protect other market participants if a QTU is not completed before the delivery year for which it cleared a capacity auction.

Durand contended PJM could force a transmission owner to complete the project under its Tariff. “At the end of the day, we’re not talking about some kind of proposal out of the blue. It’s considered an obligation once everyone [developer, TO and PJM] signs the Interconnection Agreement,” she said.

PJM’s Hal Loomis disagreed. “PJM really doesn’t have authority to [demand] that a QTU has to be built,” he said. “Even if some sort of reliability issue is involved, there’s no link between the reliability issue and the QTU, and no assurance that it would be done. To dramatically reduce [the credit posted] seems inappropriate.”

Dave Pratzon of GT Power Group said he was concerned that “if a QTU isn’t built, other market participants will be affected in terms of reliability.”

The MIC is expected to vote on the proposed change at its next meeting on July 9.

June 10, 2014

Members Begin Work on Gas Dispatch Fixes

As temperatures soared into the 80s outside PJM offices last week, stakeholders began debating how to avoid a repeat of the operational problems from last winter.

Operating Committee members discussed a problem statement and issue charge on gas-unit-commitment coordination, a response to PJM’s problems in scheduling gas-fired plants in January.

About one quarter of PJM’s outages on Jan. 7 were the result of gas units’ inability to obtain fuel.

Gas pipeline rules caused delays in the starting of some units and restricted PJM’s ability to dispatch units as needed. The Operating Committee’s initiative will seek methods for gas generators to communicate such operating restrictions to PJM dispatchers.

It will also respond to complaints by about 10 companies that they were left with “stranded gas” when PJM failed to dispatch their units in January. Duke Energy has filed a claim in an effort to recoup $9.8 million in gas losses, and NextEra Energy Resources said it will make a similar claim to recoup $1.3 million. (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim).

“We need to get some changes in prior to next winter, even if we need to segregate short-term [solutions] from long-term,” said Mike Bryson, executive director of system operations. The short-term solution may be a simple clarification of existing rules for RTO dispatchers and generators while PJM develops a long-term solution, he said.

The Operating Committee focused on education and interest identification in last week’s session. It will continue its work in a special meeting June 23.

June 10, 2014

EPA Rule Boosts Regional Compliance, Cap-and-Trade

States could cut their costs of complying with the Environmental Protection Agency’s carbon emission rule by more than one-quarter through 2020 by joining a regional compliance program similar to the Regional Greenhouse Gas Initiative (RGGI) cap-and-trade program.

The EPA estimates total compliance costs of $7.5 billion in 2020 (2011$) if states comply individually, versus $5.5 billion if all states take a regional approach.

Costs rise to $8.8 billion (2011$) in 2030 under state compliance, compared with $7.3 billion for the regional approach.

“States may choose to cooperate in order to achieve more cost-effective outcomes, since some states can reduce their emissions more easily relative to others,” the agency explained. It “expects this flexibility to reduce the cost of achieving the state goals and therefore expects it to be attractive to states. For example, the RGGI-participating states could choose to submit a multi-state mass-based plan that demonstrates emission performance by affected [electric generating unit (EGU)] on a multi-state basis. Additional states may also choose to join a multi-state plan.”

Individual state plans must be filed with the agency by June 30, 2017, with a one-year extension possible. Regional plans won’t be due until June 30, 2018.

The EPA’s regional analysis assumed five regions based on North American Electric Reliability Corp. (NERC) regions and RTO footprints. States that fall into more than one region were grouped in the region that comprised the majority of geography or generation. Thus, the EPA’s “East Central (PJM)” region included only seven states: Ohio, Pennsylvania, West Virginia, Maryland, Delaware, New Jersey and Virginia (see map.)

Regional Zones in EPA Proposed Carbon Rule (Source: EPA)

Mass- or Rate-Based Standards

The EPA’s default state emission limits are rate-based, setting limits measured in pounds of CO₂ per MWh of generation. States have the option of converting the rate-based standards to a mass-based limit measured in tons of CO₂. The regional plans also have the choice of a rate-based standard or the mass-based caps used by RGGI. (See related story, LaFleur, Bay: ‘Flexibility’ of EPA Rules Mitigates Reliability Concerns.)

The agency invited comment on suggestions that it develop a model rule for an interstate emissions credit trading program that could be easily adopted by states.

Nine states, including Maryland and Delaware in PJM, participate in RGGI. New Jersey withdrew from the program in 2011. (See related story, EPA’s Carbon Rules Attacked from Both Flanks.) California has established an economy-wide, market-based greenhouse gas emissions trading program, which requires the state to reduce its 2020 GHG emissions to 1990 levels.

RGGI, which was created in 2009, sets an overall limit on allowable CO₂ emissions from affected generators. Participating states issue carbon allowances based on their annual emission budgets.

At the end of each three-year compliance period, affected generators must submit CO₂ allowances equal to their reported carbon emissions. The allowances may be traded among both regulated and non-regulated parties, creating a market and price signal for emissions. The price signal factors into the economic dispatch of affected generators.

Between 2009 and 2012, the RGGI states invested auction proceeds of more than $700 million in programs to lower energy costs and reduce emissions, such as energy-efficiency programs.

Power sector carbon emissions in the RGGI-participating states fell by more than 40% between 2005, when RGGI was announced, and 2012. The EPA acknowledges RGGI was not the primary driver for these reductions — reduced electric demand following the 2008 recession was a big factor. In January, the group lowered its 2014 CO₂ emission cap by 45%.

PJM Role?

The EPA also is seeking comment on how PJM and other RTOs and ISOs could help states achieve efficiencies, a role suggested by the ISO/RTO Council.

“Just as the ISO/RTO regions today share the benefits and costs of efficient EGU dispatch across state boundaries, there are significant efficiencies that could be captured by coordinating individual state plans or implementing multi-state plans within a grid region,” the agency said. “Under one variant of this approach, states would implement a multi-state plan and jointly demonstrate CO₂ emission performance by affected EGUs across the entire ISO/RTO footprint.”