Page 1626 – RTO Insider

August 5, 2014June 15, 2023

Quarterly Earnings a Chance to Highlight News

By Ted Caddell

Quarterly earnings calls aren’t only about the numbers. They are often platforms companies use to highlight other news.

Calpine last week announced plans for a new 760-MW plant in PJM, while PPL said it had proposed a 725-mile transmission line through New York, New Jersey, Pennsylvania and Maryland at a cost of $4 billion to $6 billion.

Exelon, which announced its acquisition of Pepco in its first-quarter earnings call in April, used its second-quarter earnings call to continue its push for state support for its Illinois nuclear plants.

EXELON

Exelon reported net income of $522 million, or 60 cents per share, for the second quarter this year, compared to $490 million, or 57 cents a share, for the same period last year. The 6.5% increase was due in large part to increased capacity prices in PJM, the company said.

The company — which has previously said that some of its Illinois nuclear plants are unprofitable and at risk of closing down — hopes to win state incentives for the plants’ contribution to the economy and their role in helping the state comply with the Environmental Protection Agency’s proposed carbon emissions rule.

“State agencies are drafting a number of reports that will look at the economic value of the units to the local communities, jobs, the value of the energy produced, the value of the low carbon resources,” said Joseph Dominguez, Exelon’s senior vice president of government and regulatory affairs. He said he expected to see the reports in November or December.

“It’s pretty clear that if you lose nuclear plants, your ability to comply with any carbon regime going forward is going to be jeopardized,” CEO Chris Crane said.

PPL

PPL reported earnings of $229 million, or 34 cents per share, compared to $405 million, or 63 cents per share, last year. That included a special charge of $128 million, or 19 cents per share, related primarily to the anticipated spinoff of PPL Energy Supply.

“Strong performance at each of our regulated utilities with stronger margins from our competitive Energy Supply business led to very solid results through the first half of the year,” CEO William H. Spence said.

Route of PPL's proposed transmission line. — Route of PPL’s proposed transmission line.

Spence announced that PPL has submitted to PJM a proposal to build a 725-mile, 500-kV transmission line that would run from Western Pennsylvania into New York and New Jersey, with another spur running south into Maryland. Spence estimated the cost for the project at between $4 billion and $6 billion. He said if construction begins by 2017, the project would be completed by 2023 to 2025.

The project was submitted to PJM as part of the Regional Transmission Expansion Plan “window” that opened June 27. (See RTEP Proposal Window About a Month from Opening.)

PPL said the line would address both reliability and congestion as well as move power expected to be produced by new generators fueled by shale gas in northern Pennsylvania. Spokesman Paul Wirth said it would address reliability problems on three 230-kV lines: Lackawanna-North Meshoppen, Montour-Sunbury and Siegfried-Frackville.

CALPINE

Calpine reported a profit of $139 million, or 33 cents per share. During the same period last year, it showed a loss of $70 million, or 16 cents per share. Operating revenues drove most of the improvement, as they climbed from $1.57 billion to $1.94 billion, an increase of about 23%.

Calpine signaled its confidence in the PJM market by announcing a new 760-MW generator at its York Energy Center near Delta, Pa. It is to be built on the site of its existing 565-MW combined-cycle plant. Using existing infrastructure will result in construction savings, and its location will allow it to take advantage of shale gas from Pennsylvania fields, according to CEO Thad Hill.

PEPCO

Pepco Holdings Inc. reported adjusted net income of $71 million, or 28 cents a share, compared to $53 million, or 21 cents per share, last year. The company credited higher electric distribution and transmission revenue and lower operation and maintenance expense for the uptick.

Pepco reported that applications for approval of its acquisition by Exelon have been filed with the Federal Energy Regulatory Commission, the Virginia State Corporation Commission, the Delaware Public Service Commission, the D.C. Public Service Commission and the New Jersey Board of Public Utilities.

Filings with the Maryland Public Service Commission are expected in the coming quarter.

DOMINION

Dominion Resources reported earnings of $159 million, or 27 cents per share, compared to $202 million, or 35 cents per share, last year, a decline of 21%. The company attributed the dip to milder weather, and a one-time charge resulting from Virginia legislation that permitted the company to recover 70% of the costs previously deferred or capitalized relating to the development of a third nuclear unit at North Anna and offshore wind facilities. Revenue declined to $2.81 billion from $2.98 billion, or 5.6%.

Thomas F. Farrell II, Dominion’s chairman, president and CEO, noted on a conference call that the company recently received an environment assessment approval from FERC for its Cove Point LNG facility in Maryland. Farrell also noted the company’s acquisition of two solar projects in Tennessee and an agreement to acquire its seventh in California, bringing its total solar projects in operation or development to 232 MW.

AEP

American Electric Power reported earnings of $390 million, or 80 cents per share, compared to $338 million, or 69 cents per share, last year, an increase of about 15%.

CEO Nicholas K. Akins said the company’s regulated transmission business brought in 10 cents per share for the quarter, up from 4 cents for the same period last year. It is a part of the business AEP is counting on.

“The additional $300 million that we’ve allocated to our transmission business in 2014 brings our total transmission capital investment to approximately $1.9 billion, which will support future earnings growth,” Akins said.

PSEG

Public Service Electric Enterprise Group reported a profit of $212 million, or 42 cents a share, compared to $333 million, or 66 cents a share, for the second quarter, a drop of 36%.

An extended outage of its Salem nuclear station’s Unit 2 was the cause of some of the decline. PSEG Power, the company’s generation arm, showed a 74% drop in net income, from $210 million in the second quarter of last year to $54 million for the same period this year.

The company’s regulated utility business reported a 25% rise in profit — $151 million on revenue of $1.435 billion this year, from $121 million on $1.423 billion last year.

“The primary driver of growth — increased investment in transmission in our utility PSE&G — remained strong in the second quarter, offsetting the impact from mixed operating conditions,” PSEG Chief Executive Ralph Izzo said.

August 5, 2014June 15, 2023

FERC Split on Reliability Analysis of EPA Rule

From left to right: FERC Acting Chair Cheryl LaFleur; Commissioners Philip Moeller, John Norris and Tony Clark; and Office of Enforcement Director Norman Bay. — From left to right: FERC Acting Chair Cheryl LaFleur; Commissioners Philip Moeller, John Norris and Tony Clark; and FERC Office of Enforcement Director Norman Bay.

WASHINGTON — Summoned to Capitol Hill, members of the Federal Energy Regulatory Commission last week revealed differences over the impact of the Environmental Protection Agency’s proposed carbon emission rule but declined to endorse climate change skeptics’ do-nothing strategy.

Speaking before the House Energy and Commerce Committee’s energy and power subcommittee, Commissioner Philip Moeller renewed his call for a reliability analysis on the impact of expected coal-plant shutdowns while Acting Chair Cheryl LaFleur and other members said such a study was premature.

Moeller and fellow Republican Tony Clark expressed more concern over the rule than the commission’s Democrats. But they refused to join subcommittee Chair Ed Whitefield (R-Ky.) and other Republicans in saying the EPA was wrong to act on climate change.

Whitfield dismissed warnings of increasing droughts, saying they were belied by this year’s bumper corn crop. He also rejected claims that the EPA acted because Congress had failed to do so. “Congress did act by deciding not to act” to approve a cap-and-trade bill in 2010, Whitfield said.

No Takers

California Democrat Henry Waxman, co-sponsor of the bill, got his chance to respond a few minutes later, asking the commission members to raise their hands if they believed “there is no need to deal with climate change.” None did.

“We can reduce carbon emissions and keep the lights on,” Commissioner John Norris said. “I feel Congress is missing the point. [The EPA’s proposed rule] is a very gradual transition and a very necessary transition.”

LaFleur pushed back when Texas Republican Joe Barton said the EPA rule appears to conflict with FERC’s mandate to ensure power “at reasonable cost.” (LaFleur was named chairman effective July 30. See related story, Bay to Take FERC Gavel April 15.)

“I do not see the rule as inconsistent with FERC’s responsibilities,” she said.

The proposed rule seeks to reduce carbon dioxide emissions from electric generation by 30% from 2005 levels. The EPA set reduction targets for individual states based on four “building blocks”: unit-level efficiency improvements for coal-fired units; fuel switching from coal to natural gas; renewable energy and nuclear power; and demand-side energy efficiency.

In written responses to the subcommittee’s questions, the members revealed that none but LaFleur had any discussions with the EPA prior to the release of the proposed rule June 2. LaFleur said she or FERC staff met with EPA or Office of Management and Budget officials on seven occasions between February and July and that FERC had told officials of the need to respect reliability concerns in drafting the rule.

Norman Bay Speaks

The session included FERC enforcement Director Norman Bay, who was confirmed as the commission’s fifth member last month and is awaiting his swearing in. Bay demonstrated that his transition from behind-the-scenes prosecutor to a commissioner is a work in progress, forgetting twice to press his microphone before speaking. Bay professed confidence that “the challenges [of implementing the rule] are manageable.”

Bay also was pressed by Texas Democrat Rep. Gene Green on his running of FERC’s Office of Enforcement. Green said FERC should create an office of compliance to provide “more transparency” to energy traders seeking to avoid running afoul of commission rules. Bay said FERC already maintains a help line and issues “no-action” letters in response to questions about market rules.

Call for Reliability Analysis

The session provided Moeller an opportunity to renew his call for a FERC-led reliability analysis. Moeller noted that the EPA has identified 180 GW of coal-fired generation that it expects to be shuttered as a result of the carbon rule and the Mercury and Air Toxics (MATS) rule, which takes effect next year.

Moeller acknowledged that disagreements on the reliability implications are likely but said “a reliability study shouldn’t be that difficult.”

“Getting the electricity reliability experts together in a public and transparent forum to address these questions and develop answers is the responsible approach. Engineers can debate and disagree on details, but presently there is no public forum for this discussion to occur,” Moeller said in written testimony. “Although the EPA’s proposal mentions the concept of reliability more than a hundred times, it’s the details of calculating proper reserve margins and specific load pockets that matter from a reliability perspective.”

But others on the commission agreed with LaFleur, who said that a study “could be more speculative than informative” due to uncertainty over the requirements of the final rule and how it will be implemented by the states.

“You’re not going to prove it is or isn’t going to work because it’s still in development,” Norris told the subcommittee.

Questioning EPA Assumptions

Moeller also raised questions about several of EPA’s assumptions, including its expectation that natural gas generators will reach dispatch factors of 70% and that there will be enough pipeline capacity built to support a change from coal to natural gas.

Moeller said 70% gas dispatch “has been very rarely done in this country.”

Moeller said officials haven’t figured out a way to obtain financing for pipeline expansions to serve generators and that the EPA “doesn’t fully understand the challenges.” Generators are reluctant to sign long-term gas supply contracts — which traditionally have enabled financing of pipelines — because of uncertainty over how much they will be dispatched.

Norris said the increase in natural gas-fired generation capacity assumed by the EPA will be “challenging but not impossible.”

Moeller also suggested the rule could inhibit economic growth by “essentially capping” electricity consumption in 2030 and differed from LaFleur on whether the EPA had adequately accounted for interstate power flows.

Clark said he feared a “jurisdictional train wreck” between the EPA and FERC and said states may be forced into a “‘mother-may-I?’ relationship” with the agency, which will pass judgment on individual State Implementation Plans (SIPs). Once approved, SIPs could limit states’ ability to change building codes and renewable portfolio or energy-efficiency standards, Clark said.

Impact on RTOs

Much of the discussion concerned the rule’s likely impact on PJM and other RTO markets. Moeller said the rule would result in a shift from economic dispatch to “environmental dispatch.”

“It’s a fundamental change … with how the system operates. It needs to be examined very carefully,” Moeller said.

LaFleur said it was “too soon to speculate” on the impact on RTOs. She and Norris expressed confidence in RTOs’ ability to respond, noting that PJM and others have incorporated regional cap-and-trade programs and state renewable portfolio standards into their market operations.

“We’ll have a much better idea of the challenges once the SIPs are done,” LaFleur said.

August 5, 2014June 15, 2023

Company Briefs

A state appeals court decided that Commonwealth Edison must pay for the spoiled groceries and other costs that 35,000 of its customers suffered from a series of 2011 storms. The decision could set a precedent and force the company to pay in future cases.

The ruling upheld a 2013 decision by the Illinois Commerce Commission resulting from six summer storms and a blizzard in 2011. ComEd has said the decision could cost it up to $35 million in claims.

More: Chicago Tribune(subscription required)

Exelon Files Ginna Petition with NYPSC

Exelon signaled that its Ginna Nuclear Power Plant in Ontario, N.Y., will remain a part of its nuclear fleet when it filed a petition for continued operation with the New York Public Service Commission. Earlier in the year, published reports indicated that the company was considering shutting the plant down, arguing that it was uneconomical.

The petition, filed in late July, indicates that the company will keep the 581-MW Ginna plant running if it gets a good enough power-purchase contract from Rochester Gas and Electric. An earlier study conducted by NYISO indicated that the plant was necessary for the continued reliability of the grid. Without that study, Exelon said, it would have considered shutting down the plant.

More: Power Magazine

New York May Force Indian Point Outages

Entergy’s Indian Point Nuclear Plant may be temporarily shut down by an order from the New York Department of Environmental Conservation in a move designed to protect fish populations.

The outages, which would affect both units, could be for 42, 62 or 92 days a year, the department has proposed. The outages would take place between May and August of each year during the plant’s 20-year license extension period.

Entergy Vice President of License Renewal Fred Dacimo said taking the units offline during peak energy consumption months would result in increased prices and could lead to blackouts. “All of these impacts might be worth considering if outages at Indian Point were actually necessary to protect fish eggs and larvae, but they are not,” he said. He said Entergy has proposed alternate methods to protect aquatic wildlife.

More: Nuclear Street

Bolts in Salem Failure Deemed Unsuitable in ‘84

Bolts that caused an extended outage at Unit 2 of Public Service Enterprise Group’s Salem nuclear plant were composed of an alloy that had been ruled unfit for use in nuclear equipment as far back as 1984, according to findings by the Nuclear Regulatory Commission and other sources.

The failure of the bolts, which were inside two reactor coolant pumps, was found during a scheduled offline period in April as the reactor underwent fuel replacement. PSEG announced in mid-May that the shutdown would be extended to fix the problem. The company restarted Unit 2 last month.

The manufacturer of the bolts, Westinghouse Electric, warned that parts loosened by bolt failures could have created a “substantial safety hazard” if they locked up rapidly spinning parts in one or more of the coolant pumps, according to NRC spokesman Neil Sheehan.

PSEG spokesman Joe Delmar said that Westinghouse issued a technical bulletin on the issue in 1996. The bulletin concluded that even if all bolts on a pump failed, “it would not affect the performance of the pump and, therefore, they did not recommend going in and replacing the bolts with others with different material unless you were going into the pump for another purpose,” Delmar said.

The NRC notified officials at Dominion’s Surry Units 1 and 2 reactors near Newport News, Va., of the problem. Surry is the only other plant to use the same “A-286” alloy bolts in coolant pumps. Dominion is reviewing reports from Salem “to evaluate a course of action going forward,” Sheehan said.

More: The News Journal

DTE Closing Down 2 Mich. Coal Units

DTE Energy will close two units at its Trenton Channel coal plant in Trenton, Mich., in 2016 in part because of new Environmental Protection Agency emissions rules, the company announced last week. The two units generate a total of 210 MW. The closings will leave a single unit in operation at the plant, the 520-MW Unit 9.

“The decision was made because of new federal emissions regulations taking effect in the next few years, and because of DTE’s focus on reducing customers’ rates and maintaining competitive electric rates in the future,” DTE Randi Berris said.

More: The News-Herald

August 5, 2014June 15, 2023

Exelon, Pepco Reject Merger Objections

Exelon and Pepco told the Federal Energy Regulatory Commission last week that competitive and environmental concerns raised by the Independent Market Monitor and others over their proposed merger are unfounded, reiterating their request for FERC approval by Aug. 30.

“None of the objections to the transaction has any merit, and the commission should approve it without conducting an evidentiary hearing or imposing additional conditions,” the companies said in a July 30 filing (EC14-96).

Although the transaction will not substantially increase Exelon’s generation portfolio — Pepco owns only 17 MW — commenters have told FERC the pairing threatens to hurt competition, the health of the Chesapeake Bay, prospects for renewable energy and the PJM stakeholder process.

Commenters also asked FERC to ensure that costs of the transaction are not passed on to transmission customers and to strengthen provisions to prevent cross-subsidization among Exelon’s subsidiaries.

Competitive Concerns

The IMM said FERC should require the companies to provide more information and impose behavioral mitigation to address “potential vertical and horizontal market power issues.”

The Monitor said that Exelon’s ownership of the intrastate natural gas distribution systems of PECO Energy and Baltimore Gas and Electric, combined with the gas assets of Pepco’s Delmarva Power & Light unit, raise concern over gas-fired generators’ access to fuel.

Julie Solomon of Navigant Consulting, who evaluated the competitive impact of the merger on behalf of the applicants, said that new gas-fired generators will likely connect directly to interstate pipelines and bypass Exelon’s local distribution companies (LDCs).

But the IMM said the application did not discuss the state rules for such bypass arrangements and whether LDCs can impose charges or other conditions on generators seeking service directly from an interstate pipeline.

The Delaware Public Service Commission said Exelon and Pepco’s LDCs have the potential to favor their generation affiliates “especially during periods when interstate natural gas pipelines in the Mid-Atlantic are severely constrained,” because they hold gas storage entitlements and firm transportation contracts on interstate pipelines.

Exelon and Pepco said their combination will hold 6% of the interstate pipeline capacity in PJM and 7-8% of the capacity in the AP South region and the 5004/5005 submarket in Maryland. Their share of natural gas storage in PJM will be about 2.5%.

The Delaware PSC also said the companies should demonstrate that they cannot use their LDCs’ pipeline capacity entitlements to raise delivered natural gas prices “and, consequently, electricity prices to the advantage of their generation affiliates.”

Exelon said that because it already owns BGE and PECO, “the only potential vertical market power concern” raised by the merger relates to Pepco’s Delmarva affiliate, “which does not serve any natural gas-fired generation from its local distribution facilities.”

“Certainly the Delaware PSC can make no claim that any of the applicants have ever improperly withheld gas transportation capacity or that the transaction in any way would facilitate the improper withholding of such capacity,” the applicants said.

Exelon Transmission Concentration

The IMM said that the increased ownership of transmission is also a concern and that the applicants overstated PJM’s control over their assets. The merger would give Exelon nearly one-quarter of the PJM transmission network, adding Pepco’s transmission, which accounts for 6.6% of PJM transmission service credits, to Exelon’s current 16.8%.

The IMM also said FERC should consider the impact of the merger on competition among transmission developers under FERC Order 1000.

Transmission owners can determine “the timeliness, the technical requirements for and the costs of” interconnections and set the line limits used by the RTO in their network models, the IMM said.

Exelon “will have substantial and increased influence over decisions that directly relate to competition in PJM among developers of transmission projects. Although the RTO has responsibility for the interconnection process, transmission owners perform interconnection studies for generation. Having a transmission owner involved in the study process creates a conflict of interest if they are also the developer or potential developer of a project or own competing generation,” the IMM said.

The IMM said FERC could address its concerns through behavioral mitigation, such as ordering independent interconnection studies and a process for reviewing and updating transmission limits.

Exelon said the IMM’s concern is “purely hypothetical [and] completely unsupported by any data or other evidence.”

It said its market power is mitigated by both its membership in PJM and FERC’s requirement that all transmission providers operate under the competitive protections of an Open Access Transmission Tariff.

Impact on Transmission Rates

The Southern Maryland Electric Cooperative (SMECO) and the Delaware Municipal Electric Corp. said FERC should prohibit Exelon from recovering its “acquisition premium” — the 25% difference between Pepco’s stock market value and Exelon’s purchase price — through wholesale transmission rates.

SMECO, which depends on seven interconnections with Pepco to supply its members, said that while Exelon promised not to seek recovery of the premium through retail rates, it made no such commitment to wholesale transmission customers. SMECO said FERC should insist Exelon’s promise to hold transmission customers harmless for five years applies to both the acquisition premium and transaction costs.

It also called for revisions to Pepco’s existing formula transmission rate to improve transparency and ensure customers have the information needed to review and challenge future rate-increase requests.

Exelon said it should not be prohibited from recovering merger-related costs if they are offset by merger-related savings. The applicants said FERC lacks jurisdiction to require changes to formula-rate protocols in the merger proceeding. “Such changes to an existing rate schedule may be ordered only in connection with a Section 206 complaint,” the company said.

Cross Subsidization

In their May 30 application to FERC, Exelon and Pepco said that “because of the de minimis nature of the competitive overlap,” the commission should be able to approve the transaction within 90 days.

The Delaware Municipal Electric Corp. said FERC should reject the applicants’ request for an expedited ruling, noting that state regulators have not yet examined the adequacy of the “ring-fencing” measures to address cross subsidization.

The D.C. Office of the People’s Counsel said the financial and geographical size of the merged company raises questions of “whether any one state regulatory body will be able to regulate the local utility subject to its jurisdiction.” The post-merger company would have regulated utilities in Illinois, Pennsylvania, Maryland, Delaware, New Jersey and D.C.

Exelon responded that the merger satisfies the commission’s cross-subsidization standards so that “no particular ring-fencing should be required.”

Environmental Concerns

The Clean Chesapeake Coalition, a group of nine northern and eastern Maryland counties, complained that Exelon — whose post-merger service territory would surround the Chesapeake Bay and its tributaries — has displayed a “lack of environmental due diligence.”

The coalition wants Exelon to do more to prevent sediment trapped by the dam at the Conowingo Hydroelectric Project from being released into the Chesapeake during storms.

The counties said they approached Exelon to express their concerns — at FERC’s direction — after attempting to intervene in the relicensing of the dam. They said that the company has not responded after more than three months. “Such disregard of local government concerns [is] an affront to the public interest,” the coalition said.

The Institute for Energy and Environmental Research and the Nuclear Information and Resource Service, two Maryland-based environmental groups, said the merger will increase Exelon’s influence in public policy debates over the merits of nuclear power versus renewables. Exelon would increase its share of residential electric distribution customers from 50% to 80% in Maryland while adding virtually all D.C. residents.

Exelon has been seeking additional compensation for the carbon-free generation of its nuclear fleet. The environmental organizations said this pits Exelon’s interests against those who support more renewables. The groups cited Environmental Protection Agency estimates that reducing carbon emissions through renewable portfolio standards costs $3 per metric ton while subsidizing “at-risk nuclear units” would be $12 to $17 per metric ton.

“If corporate money is free speech, as the Supreme Court has ruled, then FERC is obliged to consider the effect of increasing Exelon’s ability to speak in the political arena that the merger would cause,” the groups said.

Exelon said the environmental claims are “irrelevant to the commission’s review” of the merger.

PJM Influence

The IMM, Delaware PSC and D.C. Office of the People’s Counsel complained that the merger could give Exelon undue influence in the PJM stakeholder process.

Having divested its generation, Pepco has more in common with transmission-only cooperatives than generation owners such as Exelon; Pepco representative Gloria Godson has often sided with load against supply in PJM debates. (See Pepco to Lose its PJM Voice; Consumers Lose Frequent Ally.)

“The potential for the elimination of [Pepco]’s independent voice in the PJM stakeholder process should give this commission serious pause,” the DC Office of the People’s Counsel said.

The Delaware PSC noted that Exelon is a member of the Electric Power Supply Association (EPSA), the plaintiff in the lawsuit that resulted in an appellate court voiding FERC’s authority over compensation for demand response. “Exelon’s support for that outcome is not in line with consumer interests,” the Delaware regulators said.

The IMM said that “transmission owners have significant leverage” over RTOs and noted that Exelon’s participation in PJM is voluntary.

“Like any organization, RTOs are concerned with protecting their size, scope and importance. The exit of a transmission member would be a very significant negative for an RTO,” the IMM said. “The greater the proportion of the RTO’s assets represented by the transmission owner, the greater the threat of exit to the RTO and the greater the potential influence of the transmission owner over the RTO governance and processes.”

Exelon said the claims are irrelevant and incorrect.

Pepco and Exelon each have one vote in PJM’s top two stakeholder bodies, the Members Committee and Markets and Reliability Committee — Pepco in the Electric Distributor sector and Exelon in the Transmission Owner sector. Post-merger, Exelon will have only one vote in the 14-member TO sector.

“Consequently, far from increasing Exelon’s influence in the stakeholder process, the transaction will reduce by one vote the influence the merged company will have,” Exelon said.

August 5, 2014

PJM Plans Section 206 Filing on FMUs

PJM’s Board of Managers will ask the Federal Energy Regulatory Commission to approve a proposal opposed by generators to reduce payments to frequently mitigated units (FMUs).

General Counsel Vince Duane told the Markets and Reliability Committee last week the RTO will make the request under Section 206 of the Federal Power Act because the proposal by PJM and the Independent Market Monitor failed to win two-thirds of the Members Committee in June.

The plan garnered a 65.6% sector-weighted vote of the committee, with support from only 23% of Generation Owners and about half of Transmission Owners and Other Suppliers. End Use Customers and Electric Distributors voted unanimously in favor of the proposal, which would limit FMU adder payments to units whose net revenues are not covering their avoidable cost rate (ACR). (See FMU Proposal Falls Short.)

August 5, 2014

Norman Bay to Take FERC Gavel April 15

President Obama last week named Cheryl LaFleur as chairwoman of the Federal Energy Regulatory Commission effective July 30 and said new Commissioner Norman Bay will succeed her in the top spot on April 15, 2015.

LaFleur has been serving as acting chair since Nov. 25, when former Chair Jon Wellinghoff resigned.

Bay, who has served as director of FERC’s Office of Enforcement since 2009, won confirmation to the commission under an unusual agreement that Obama wouldn’t promote him to the chairmanship for nine months.

The compromise was crucial to winning the votes of some who criticized Obama’s plan to make Bay — who has never been a regulatory commissioner — chair immediately upon his appointment.

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

LaFleur has served on the commission since 2010. (See At FERC, Uncertainty Remains Despite Norman Bay’s Nod.)

August 5, 2014June 15, 2023

NCEMPA to Sell 700 MW of Generation to Duke

The four-unit, 2,422-MW coal-fired Roxboro Steam Plant in in Semora, N.C., is one of the largest power plants in the United States. (Source: Duke)

The North Carolina Eastern Municipal Power Agency is selling its stake in four Duke Energy Progress power plants to Duke in a deal valued at $1.2 billion, the organizations announced last week.

The agreement involves about 700 MW at two coal-fired plants and three nuclear units. When the deal closes, Duke will be the sole owners of the Roxboro Unit 4 and Mayo Unit 1 coal plants, and the Brunswick Units 1 and 2 and Harris Unit 1 nuclear stations. All of the plants are in North Carolina.

Duke also entered into a 30-year power-purchase agreement to supply wholesale power to the 32 municipalities represented by NCEMPA. The terms of that agreement were not released.

The deal will allow the agency to unburden itself of a large chunk of the approximately $1.9 billion in debt under which it has been struggling.

The single-unit, 900-MW Harris Nuclear Plant is located near New Hill, N.C. (Source: Nuclear Regulatory Commission)

“NCEMPA’s decision to sell its power generating assets was driven by a desire to lower its power costs and reduce its risk of generation ownership,” said NCEMPA spokesperson Rebecca Agner on Friday. “This agreement will reduce NCEMPA’s outstanding debt by more than 70% and make our costs more competitive. After the sale, NCEMPA will not own any generation assets.”

The agreement needs approval from the Federal Energy Regulatory Commission and several state agencies.

Duke spokesman Jeff Brooks said the agreement was attractive for the company for a number of reasons. He acknowledged that the $1.2 billion sales price was somewhat higher than “book value” of the plants, but he said having sole ownership “will provide long-term fuel savings,” benefiting both Duke and its customers.

“These units were among the least costly [in the Duke fleet] to operate from a fuel standpoint,” he said. In buying back the 700 MW of capacity, Duke will be able to increase wholesale energy revenue while lowering its average fuel costs.

Municipalities will benefit from lower debt service costs.

Although Duke has retired a number of coal units in the region in recent years, the Roxboro and Mayo plants are among its youngest and have already seen substantial emissions control retrofits.

“We have made substantial investments in emissions control and dry ash” collection, Brooks said. “The coal units are among the cleanest in the nation.”

The two nuclear stations could run for at least two decades. The licenses for Brunswick Units 1 and 2 are good until 2034 and 2036, respectively. The Harris license expires in 2046.

August 5, 2014

PJM MRC Briefs

The Markets and Reliability Committee last week endorsed two manual changes and approved changes to rules on black start compensation and auction-specific transactions.

Manual Changes

Members endorsed changes to Manual 37: Reliability Coordination to update the System Operating Limits (SOL) definition and violation language (sections 3.1, 3.2) to conform to the North American Electric Reliability Corp. standard.

Revisions to the cost allocation section of Manual 14B: PJM Region Transmission Planning Process also won endorsement. The changes describe the current solution-based methodology as detailed in the PJM Tariff.

Revisions to Manual 14A: Generation and Transmission Interconnection Process were deferred to await coordination with MISO. The revisions are intended to reflect changes in how interim deliverability studies are conducted.

Black Start Compensation, ‘Back Stop’

Members approved a “back stop” mechanism for acquiring black start services through transmission providers when PJM solicitations fail to obtain service for a zone. Members also approved minor Tariff and manual changes relating to the compensation of black start units. (See PJM to Seek Smaller Black Start Changes.)

The new rules:

Allow energy-only black start units to be compensated. There was previously no mechanism to compensate energy-only generators through the base formula rate.
Allow automatic load rejection (ALR) units to recover NERC Compliance costs as documented to the Market Monitor.
Allow fuel-storage compensation for liquefied natural gas, propane and oil. Previously, only oil storage was compensated.
Limit black start units sharing a common fuel tank to claim the fuel-storage compensation for only one unit, closing a loophole.
Schedule a review of compensation formulas every five years (down from the current two years) to align it with the RTO-wide black start solicitation.

The System Restoration Strategy Senior Task Force had considered several proposed changes but none of the others received the minimum 50% support to forward it to the MRC for consideration. With its work complete, the task force will be sunset, said MRC Chairman Mike Kormos, PJM’s executive vice president for operations.

Auction-Specific Transactions

Members gave final approval to a manual change that will make it easier for banks to purchase capacity providers’ revenue streams. The change, proposed by Citigroup Energy, will allow auction-specific transactions to be entered into PJM’s eRPM system after the auction that initiated them. Previously, such transactions could not be submitted to PJM until after the third incremental auction for a delivery year. (See Stakeholders Look to Expedite Auction-Specific Transactions.)

August 5, 2014June 15, 2023

PJM to Hike Penalties, Incentives to Improve Winter Reliability

PJM will increase performance penalties and incentives and seek ways to incorporate firm gas transportation in energy prices under an initiative announced last week to reduce generator outage rates.

PJM CEO Terry Boston announced the initiative, which he said resulted from a three-day meeting of the Board of Managers and discussions with present and former leaders of the Members Committee and stakeholder sectors.

The action was prompted by January’s extreme cold, when as much as 22% of PJM’s generation suffered forced outages, three times the normal winter rate.

“We would have to interrupt load if this happened in [future] winters,” Boston told the Markets and Reliability Committee Thursday, noting that the RTO will lose about 8,500 MW of generation to retirements by the winter of 2015/16. “We feel [changing capacity rules] has to be one of our highest priorities.”

Officials said the changes may increase capacity costs but should also reduce volatility during tight supply/demand conditions.

Redefinition of Capacity

“You should think of this as a holistic redefinition of what capacity is,” said Andy Ott, executive vice president for markets.

Members’ initial response to the initiative — which PJM said would be conducted under expedited procedures outside the normal stakeholder process — was muted.

David “Scarp” Scarpignato of Direct Energy questioned whether PJM would bring proposed changes to “advisory” votes before the MRC or Members Committee.

Gregory Carmean, executive director of the Organization of PJM States (OPSI), expressed concern that additional costs would be largely for winter performance while capacity cost allocation is based on summer loads.

Carl Johnson, representing the PJM Public Power Coalition, expressed misgivings over the initiative during a later MRC discussion regarding the Triennial Review of capacity auction parameters.

Johnson said stakeholders haven’t received enough information on the cost impact of the parameter changes, which include a potential increase in the Installed Reserve Margin. Referring to PJM’s plans to “redefine” capacity Johnson said, “When we don’t understand what we’re buying when we buy capacity, to say we’re going to be buying more of it, we cannot support.”

The Consumer Advocates of PJM States discussed the initiative yesterday and was expected to issue a statement later this week.

Fuel Security

A key part of the new definition will be fuel security, meaning incentives are likely to encourage nuclear generators, dual-fuel units and firm gas contracts.

“At 20 mph [the speed at which gas flows], there’s not a lot of difference between just-in-time delivery and too dang late,” Boston said.

He also referred to two coal plants that were unable to operate in January because they lacked natural gas needed to start up. “Twenty thousand dollars’ worth of fuel oil could have brought those units up,” Boston said. “I would pay that now.”

More Flexible Operations

Officials also will be seeking to reverse a trend toward less flexible unit operating parameters. In a 23-page white paper issued Friday, PJM said unit flexibility has dropped as a result of staffing reductions and other cost cuts. (See Problem Statement on PJM Capacity Performance Definition.)

Ott said limits on unit flexibility must be a function of operational limits, not financial concerns. “We’ve seen units with three starts per day reduced to one; units with very short minimum run times became very long minimum run times,” he said.

The effort will also seek to boost operations and maintenance spending to improve generator availability on “low probability peak events” such as January’s polar vortex or last September’s unexpected heat wave.

“Generation owners may choose to cut O&M costs or choose not to make investments that enhance availability as a means to manage costs,” the report noted. “In making such a decision, the generation owner has implicitly or explicitly made a calculation that the benefits of such measures [increased net revenues] do not cover these ‘additional’ costs.”

Generator owners also have complained that there is no way to reflect such costs in supply offers.

“Competitive pressure to clear in the RPM capacity market may push generation owners to not make these investments if they feel other competitors are taking a similar strategy due to the risk of pricing themselves out of the market,” the report said.

Insufficient Penalties

PJM said current penalties for capacity resources that are unavailable during the 500 “peak” hours per year are insufficient.

The Tariff defines summer peak hours as Hour Ending 1500 to HE 1900 on non-holiday weekdays from June through August. Winter peak hours are HE 800 to HE 900 and HE 1900 to HE 2000 on non-holiday weekdays in January and February.

Penalties are assessed only if the forced outage rate during peak hours (EFORp) is more than the five-year average forced outage rate (EFORd5) of the resource.

Generators are often able to avoid even these penalties because the Tariff forgives outages related to a lack of gas as “Out of Management Control (OMC).”

“The penalties for being unavailable during the pre-defined peak hours … provides no incentive to make investments in O&M or infrastructure to enhance availability since there is little risk of incurring a capacity market penalty for being unavailable during reliability critical events,” the report said.

The current structure “provides an incentive for generation owners to hide the real cause behind an outage, or to shift the cause of an outage to a third party such as a gas pipeline” and claim it as OMC, the report said. However fuel delivery contracts and installation of dual-fuel capacity “are business decisions well within the control of the generation owner.”

‘Enhanced’ Liaison Committee Process

PJM officials said they will invoke a never-used “Enhanced Liaison Committee” process so that the new rules can be filed with the Federal Energy Regulatory Commission in time for the winter of 2015/16.

“If Polar Vortex conditions occurred in 2015/16 and outage rates were as high as PJM experienced in January 2014 … PJM would almost certainly experience a loss-of-load event,” the report said. PJM hopes to reduce outages this winter by resuming winter generation testing.

The process — developed by the Governance Assessment Special Team (GAST) in 2011 and documented in Manual 34 — was created to allow members to provide input on issues for which consensus is unlikely and the board acts independently.

“There will be a lot of opportunity in the next two months for dialogue,” promised Dave Anders, director of stakeholder affairs.

PJM has scheduled two meetings — 1-4 p.m. Aug. 12 and 18 — to discuss the initiative and the problem statement white paper.

On Aug. 20, PJM plans to release a draft white paper detailing proposed solutions; it will be the subject of a third meeting from 9 a.m. to noon Aug. 22. Stakeholders’ written comments on the second paper will be due Sept. 12, followed by a fourth meeting to receive additional comments Sept. 24.

The enhanced liaison process will begin Oct. 7 when PJM issues the final version of its solutions whitepaper. Additional input from stakeholders will come through coalitions, which will be required to submit briefing papers by Oct. 28.

The board will meet with the Enhanced Liaison Committee Nov. 4.

The proposed solutions may incorporate cold-weather initiatives being conducted by other committees, including energy storage participation in RPM (Planning Committee); qualifying transmission upgrade (QTU) credits and unit market offers (Market Implementation Committee); and cold weather resource performance improvements and gas unit commitment coordination (Operating Committee).

Arbitrage Technical Conference

General Counsel Vince Duane said PJM will ask FERC to delay scheduling of a technical conference the commission ordered in May, when it rejected the RTO’s plan to curb speculation in capacity market auctions. The conference is to develop solutions to eliminate arbitrage opportunities between the base residual auction (BRA) and incremental auctions (IAs).

“Any conversations with FERC thus far I would characterize as very preliminary,” Ott said in response to a stakeholder question.

August 5, 2014

Exelon to Buy Retailer Integrys for $60M

Exelon, a company primarily known for its generation fleet, continued its customer-buying spree last week when it announced an agreement to buy Integrys Energy Services for $60 million.

Integrys is a competitive retail electricity and natural gas company with nearly 1.2 million customers across 22 states and D.C.

Exelon will fold those customers in with its existing 2.5 million retail electricity and gas customers served by its Constellation subsidiary. Integrys has commercial and industrial customers across more than 100 utility service territories, primarily in the Northeast. Its residential customers are mostly in Illinois, Michigan and Ohio.

Why is Exelon getting into retail when other utilities such as Dominion are getting out?

“We continue to see growth opportunities in our competitive businesses and the value of matching load to generation, which was one of the primary reasons for our acquisition of Constellation in 2012,” Exelon spokesman Paul Adams said last week. “Integrys Energy Services is a well-run company with an attractive customer base in key markets.”

Chris Crane, Exelon’s president and CEO, also emphasized matching load to generation. “Integrys Energy Services’ geographic footprint is a perfect strategic fit for Constellation and will create opportunities to reach more customers and grow the business, particularly in regions where Exelon also owns significant generation assets,” he said.

The agreement is the latest divestment move by Chicago-based Integrys Energy Group. In June, it announced it would sell its regulated utility operations — Michigan Gas Utilities, Minnesota Energy Resources, North Shore Gas, Peoples Gas, Upper Peninsula Power Company and Wisconsin Public Service — to Milwaukee-based Wisconsin Energy for $9.1 billion.

Others have also decided to get out of the retail business. Dominion Resources announced in March it would sell its retail electric business to NRG Energy.

NRG is paying $165 million for Dominion’s 600,000 retail customers in Illinois, Maryland, New Jersey, Ohio, Connecticut, New York, Massachusetts and Texas. Exelon is paying $60 million for 1.2 million customers.

In April, the company announced plans to buy Pepco Holdings Inc., which will add nearly 2 million distribution customers to its regulated customer count while increasing its rate base to almost $26 billion from $19 billion.

In March, Exelon announced that it was buying Indianapolis-based ETC ProLiance Energy. ProLiance is a retail supplier of natural gas with about 2,500 commercial and industrial customers in eight states. The terms of that acquisition were not released at the time.

One of the prizes of buying a retail business like Integrys is that it will allow Exelon to compete for some of the valued municipal contracts its regulated utilities, such as Commonwealth Edison, have been losing to retail companies. This includes the contract for a large chunk of Chicago’s customers. In 2012, Exelon lost 700,000 residential customers in Chicago to a retail energy business — Integrys.