State Regulators Await GHG Rules

Much of the consternation at the NARUC winter conference concerned EPA’s planned CO₂ emission limits on existing generating plants (Section 111(d) of the Clean Air Act).

The regulations, expected in June, could add 60 to 100 GW in coal retirements beyond those already expected from current air and water regulations, according to the Edison Electric Institute.

Janet McCabe, EPA’s acting assistant administrator for the Office of Air and Radiation, who had addressed NARUC’s annual conference in November, was back again to provide an update on the agency’s outreach efforts.

EPA Listening Sessions

McCabe said EPA has held more than 200 meetings through January to listen to industry and state regulators’ concerns about the pending regulations.

“What we’ve been hearing: Reliability is key. Affordable energy is key. Flexibility is absolutely critical but states don’t want to be handed a blank sheet of paper. They want guideposts,” she said.

McCabe said the proposed regulations will reflect those concerns while seeking to minimize stranded assets and acknowledging differences among states in their fuel supplies and the energy intensity of their economies.

EPA’s charm offensive won praise from acting FERC Chair Cheryl LaFleur and Jon McKinney, a member of the West Virginia Public Service Commission. “In 30 years in the chemical industry and eight years as a commissioner, it’s the first time I’ve worked with EPA so closely,” McKinney said.

One of the biggest questions is whether EPA will set limits by state or establish regional caps.

ISO/RTO Council Proposal

In January, the ISO/RTO Council proposed a “Reliability Safety Valve” similar to that adopted by EPA in the Mercury and Air Toxics Standards to ensure the GHG rule includes a process to assess and mitigate reliability impacts. It also proposed allowing states the option of meeting their obligations through regional efforts whose efforts could be coordinated, and results measured, by RTOs such as PJM.

LaFleur said the regulations may require PJM and other regional transmission operators to modify their rules to accommodate state or regional plans for achieving emission cuts. “If we work together across state lines there might be an upside to help some of these states that have challenges,” she said.

“There’s lots of precedents already for [EPA] working across state lines,” McCabe said. “There’s no doubt that the program will be able to accommodate that.”

Moeller said he feared the potential for conflict between state implementation plans and interstate energy markets. Asked how FERC might referee such conflicts, he responded: “I think it’s a little early for [FERC] to be considering our role.”

Jurisdiction Questions

Colorado Public Utility Commission member Joshua Epel questioned how EPA planned to enforce the regulations. “You could be trying to bind state PUCs, and frankly I don’t think you have the authority to do that,” said Epel, who said the rules should allow a continued role for Colorado-mined coal. “We have an enormous challenge. We’ll be working together, but sometimes we’ll be slugging it out. That’s just the nature of what this is going to be.”

Joe Goffman, senior counsel in EPA’s Office of Air and Radiation, said “maybe it’s the regional NARUC entities that are best positioned … to provide a platform for” compliance.

February 20, 2014

“Free” Ride Over for UTCs?

PJM wants to change the way virtual trades pay for uplift, replacing the current unpredictable charges with a flat per megawatt fee and assessing them for the first time on up-to congestion trades (UTCs).

PJM UTC Transactions Total Volume: Jan 2010 - Dec 2013 (Source: PJM Interconnection, LLC) — PJM UTC Transactions Total Volume: Jan 2010 – Dec 2013 (Source: PJM Interconnection, LLC)

The changes would create new dynamics for financial marketers, who have increased their trading in UTCs eight-fold since 2010 while increment offers (INCs) and decrement bids (DECs) have dropped by two-thirds.

PJM outlined its plans yesterday to the Energy Market Uplift Senior Task Force (EMUSTF).

Monitoring Analytics, PJM’s Independent Market Monitor, called for assessing uplift charges on UTCs in its 2012 State of the Markets Report.

Under orders from the Federal Energy Regulatory Commission, PJM conducted a new analysis that concluded that UTCs — like INCs and DECs — affect generating unit commitments and thus can contribute to uplift costs.

PJM Analysis

PJM re-cleared its day-ahead energy market for four days in December and concluded that INCs and DECs resulted in a change of 3.1% in total unit commitments while UTCs were responsible for a change of 2.3%.

PJM said the virtual transactions should be assessed charges although it is impossible to quantify their exact impact on those charges.

“Similar to INCs and DECs, whether or not UTCs drive a more optimal solution in the Day-Ahead Energy Market will change on a daily basis and a precise determination of the direction and impact on resource commitment and dispatch by UTCs is virtually impossible due to the complexity of the Day-Ahead Energy Market and the interactions of the various different types of transactions,” PJM wrote in a report filed with FERC (ER13-1654).

The analysis found that INCs and DECs resulted in increased unit commitments. UTCs caused the de-commitment of certain units and their replacement with other units, “consistent with the energy neutrality of UTCs,” PJM said.

“However, there is not always a one-to-one tradeoff between committed and de-committed units when UTCs are removed, and the cost of the units being swapped are not always identical,” PJM wrote. “In some cases UTCs may be driving the commitment of lower cost resources in the day-ahead energy market because they are in the counterflow direction of transmission constraints and are therefore relieving congestion. In other cases the opposite will occur, and UTCs will impose forward flow on a facility in the day-ahead energy market and cause increased congestion and out-of-merit commitment and dispatch for constraint management.”

Market Monitor Analysis

In September, Market Monitor Joseph Bowring released an analysis that he said proved UTCs increase shortfalls in Financial Transmission Rights funding and disproved UTC supporters’ contention that the trades help price convergence.

While PJM says it is impossible to quantify the impact of UTCs on uplift, Bowring provided precise figures.

Over a five-day sample in May, Bowring said, FTR funding had a deficit of $4.4 million with UTCs versus a surplus of $22,000 with UTCs removed — a difference of $4.6 million.

In its 2012 State of the Market report, the monitor called for eliminating UTC transactions or making them responsible for day-ahead and balancing operating reserve charges.

The monitor said the RTO deviation rate for 2012 would have been reduced by 59% percent if UTC transactions had been included in the calculation of operating reserve charges.

PJM’s Plans

At Wednesday’s EMUSTF meeting, PJM Vice President of Market Operations Stu Bresler said the RTO will propose a flat per megawatt charge for all virtual transactions and eliminate the current variable allocation on INCs and DECs, “taking away the risk of unknown and volatile charges on the back end.”

PJM’s Dave Anders said the RTO will begin discussing the specifics of a future cost allocation with stakeholders in “Phase 2” of the task force’s work, which he said should begin in the “next month or two.”

Shake-up to Virtual Market?

PJM’s proposed change — which will face close scrutiny by financial marketers — would change the dynamics of virtual trading. (See MRC Defines UTCs; Adds Bid Limit and FTR Forfeiture Rule.)

UTCs’ use has exploded since late 2010, when PJM removed the requirement that UTCs make transmission service reservations — thus removing them from a share of uplift charges. Trading in INCs and DECs declined over the same period because of what PJM called the “strong disincentive” caused by the unpredictable uplift charges they are assessed.

Deviation charges per cleared MWh for INCs and DECs (Source: PJM Interconnection, LLC)

In 2013, INC and DEC transactions in eastern PJM paid a rate of $0.02/MWh to $33.02/MWh for deviations between the Day Ahead and Real-Time energy markets, with a mean of $3.20/MWh. Such trades in the west paid $0.02/MWh to $16.43.MWh, with a mean of $1.56/MWh. (See chart.)

“At the time rules for INCs and DECs were put in place, UTCs were not used in the speculative manner in which they are today and therefore were not included in the allocation of such charges,” PJM wrote. “However, given how the use of UTCs has evolved, it is evident, based on the fact that UTCs can shift the flow of power on the system, that they also can impact the resource commitment and dispatch of the system and consequently should be allocated a share of the applicable costs in addition to INCs, DECs and other bid and offer types that have similar impacts on the power system.”

Some stakeholders at yesterday’s meeting protested PJM’s reference to UTCs in the report as a “free transaction,” noting that they do pay administrative charges.

February 14, 2014

FERC Lifts Price Cap Through March 31

High-cost gas-fired generators will be able to set PJM market clearing prices above $1,000/MWh for the remainder of the winter, the Federal Energy Regulatory Commission ruled.

The commission granted PJM’s request for a waiver of PJM’s $1,000 offer cap through March 31, setting the stage for a contentious stakeholder debate over the long-term fate of the cap.

FERC’s order (ER14-1145) came over the objections of consumer advocates, state regulators and others, who said allowing the RTO’s most inefficient generators to set clearing prices would provide a windfall to the vast majority of generators with costs well below $1,000.

The commission sided with PJM and generators, who said the high prices should be reflected in clearing prices to provide signals for new entrants and allow market participants to hedge their risks. (See Price Cap Ruling Could Reverberate for Years.)

The order supersedes the commission’s Jan. 24 ruling (ER14-1144) allowing make-whole payments for generators with operating costs above the cap. That order allowed PJM to fund the make-whole payments through uplift charges, which cannot be hedged.

“By paying an uplift, PJM is in effect paying one price for energy dispatched through the market (e.g. $1,000), and a second higher price (e.g. $1,200) for the resource dispatched out-of-merit (while treating the latter in the dispatch stack as if it had a bid of $1,000),” the commission ruled. “This would not be consistent with longstanding Commission precedent. The Commission has previously found that `[p]ayments made only to individual resources and recovered in uplift fail to send clear market signals’ and that those resource costs `should be reflected in transparent market prices whenever possible.’”

PJM said the $1,000 cap was five to seven times higher than the marginal cost of production when the commission approved it as a market power mitigation measure.

“We did not anticipate that, when the $1,000/MWh bid cap was adopted, it would prevent marginal cost bidding,” the commission said. “Presently, however, the $1,000/MWh bid cap is preventing competitive marginal cost bids and resulting competitive prices that are needed to balance supply and demand.”

The commission dismissed concerns that lifting the cap would allow gaming, noting that generators will have to provide proof of their costs to the Independent Market Monitor. It ordered the Monitor to file a report by the end of April identifying the number of hours when clearing prices exceed $1,000, the resulting prices and total energy costs.

In addition, FERC’s enforcement staff will be monitoring the market for instances of market manipulation, the commissioners said.

The ruling will have no practical impact if natural gas prices remain at normal levels for the remainder of the winter. But if another cold snap sends prices above $100/mmBtu — as it did at some locations servicing PJM generators in January — costs to load could increase dramatically, if briefly.

FERC rejected calls that it lift the $1,000 price cap in the neighboring NYISO, which asked FERC for the more limited relief of make-whole payments funded through uplift (ER14-1138). A $1,000 cap also remains in place for MISO.

“The NYISO order is distinguished from the instant case because NYISO did not request that the marginal costs be reflected in clearing prices,” the commission said.

February 10, 2014

Ice Storm Sends Philadelphia Suburbs into the Dark – Update

In a winter of superlatives, add this: Wednesday’s ice storm cut power to more than 1 million in the Philadelphia area, with Peco Energy recording a new winter outage record.

Peco reported that about 715,000 homes and businesses lost power during the storm, more than any other in its history except for Superstorm Sandy in October 2012. PPL Electric Utilities Inc. said more than 60,000 customers lost service.

Disaster Declaration

In total, The Philadelphia Inquirer estimated, 1 million to 1.5 million of the 2.5 million residents of Chester, Delaware, Montgomery and Bucks counties lost electricity. The White House Thursday declared the region a disaster area, along with adjacent York and Lancaster counties, making residents eligible for aid from the Federal Emergency Management Agency.

Three days after the storm, more than 180,000 of Peco’s 1.6 million customers remained without service.

In New Jersey, PSE&G reported 65,000 outages while JCP&L reported a peak of 20,000. AEP Ohio was able to power to all 8,600 customers who lost service by the end of the day.

Calling for Help

Peco called on 4,000 field workers, including contractors and 2,600 linemen borrowed from utilities as far away as Canada and Arkansas. As of yesterday afternoon, Peco was still working to restore service to more than 42,000 customers and said some wouldn’t see service for days. PPL said it had restored power to all but about 600 customers.

About 87% of PECO’s customers lost power in Chester County, where officials set up shelters. To the north, Montgomery County -– home to PJM headquarters — declared a state of emergency after two-thirds of PECO’s customers went dark. (The forecast of freezing rain was enough for PJM to postpone Wednesday’s Market Implementation Committee meeting to Friday.)

Montgomery County’s 911 system had received 4,000 calls between 4 a.m. and mid-afternoon Wednesday, including 340 electrical fires, Fox News’ Philadelphia affiliate reported. The system averages about 2,400 calls a day.

Peco workers restore power following last week’s ice storm.

Ice Followed Wet Snow

The ice storm followed a wet snow Monday that had already weighed down branches.

Wednesday day brought scenes of both normalcy and crisis in Chester County. Many roads were closed and some of those that were open remained an obstacle course of downed trees and broken branches.

In Guthriesville, the managers of a powerless Burger King scrambled to load thawing French fries and hamburgers into a rental truck for transfer to a restaurant with power. About 100 yards away, a supermarket remained open thanks to generator power.

In Exton, it was standing room only at the Starbucks, which offered both power and free wifi.

At one table, a manager from Suburban Propane L.P. – whose nearby office had lost power — was calling frantic customers from her cell phone. The fuel for their generators, she assured them, was on its way.

February 10, 2014

New Susquehanna-Roseland Substations Nearly Complete

The new Hopatcong 500kV Station is nearly complete and will be energized in April, while the new Roseland 500kV Station is about a month away from completion, a PSEG representative told the Operating Committee last week. This portion of the Susquehanna-Roseland project will add 45 miles of transmission in New Jersey to reduce congestion.

The project will run from PPL’s Susquehanna nuclear plant to PSEG’s Roseland station at a projected cost of $1.4 to $1.5 billion. Transmission upgrades from Susquehanna to Lackawanna Station, and from Lackawanna station to the new Hopatcong station are expected to be completed in 2015. All regulatory approvals have been received, PSEG said.

February 10, 2014

Company Briefs

Terry Boston at Grid 20:20 — Terry Boston at Grid 20/20

PJM CEO Terry Boston has been elected to the National Academy of Engineering for leadership in the development and operation of large electric grids and wholesale electric markets. Election to the academy is through a nomination process and review by academy members. Congratulating Boston, PJM board Chair Howard Schneider said, “Behind his vision and leadership is an innovative mind, grounded in a theoretical and practical engineering foundation.”

More: PJM

Wellinghoff to Counsel New DR Group

The demand response industry is forming a trade group, the Advanced Energy Management Alliance, to exert some lobbying power in Washington and has hired Jon Wellinghoff to provide strategic counsel. The former chairman of the Federal Energy Regulatory Commission championed DR, energy efficiency and green power when he was at FERC. He joined the law firm Stoel Rives when his term expired last year.

Wellinghoff said he will help DR make its case as traditional energy suppliers defend their interests. “Without having effective representation, demand response can’t adequately expand,” he said.

More: Greentech Media

PPL to Open New Operations Center

PPL Electric Utilities will open a new operations center four miles west of its current location on Feb. 22.

A PPL representative told the Operating Committee last week that Reliability First Corp. has completed its certification of the center. Existing phone numbers will remain in effect for about the first two months.

PPL Electric Utilities runs 48,000 miles of power lines serving about 1.4 million customers in 29 counties in central and eastern Pennsylvania.

More: PPL

February 10, 2014

State Briefs

Suzlon Could End Up With Big Sky Wind Farm

Wind turbine manufacturer Suzlon Group could wind up owning the 240 MW Big Sky wind farm if negotiations between Midwest Generation and NRG Energy do not resolve a debt issue concerning the facility. Bankrupt Midwest Gen is selling assets, including Big Sky, to NRG, but complex debt arrangements could result in Suzlon taking over the wind farm. A Midwest Gen official says the company would keep operating it.

More: Crain’s Chicago Business

Smart Meter Opt-Out Fee Lower Than Expected

Customers who refuse Commonwealth Edison smart meters will be charged $21.53 a month, less than the $25 in a proposal that the utility negotiated with consumer advocates. The Illinois Commerce Commission said customers ultimately will have to get the meters whether they want them or not.

More: Chicago Tribune

MARYLAND

Bat Protection Plan OK’d

Exelon’s Indiana-bat conservation plan for its 28-turbine, 70-MW Criterion project on Backbone Mountain won approval from the U.S. Fish and Wildlife Service. The plan, required to get an “incidental take” permit under the Endangered Species Act, involves slowing blade rotation to reduce bat collisions in peak bat migration season, particularly at night, when bats are most active.

More: CBS Baltimore

NEW JERSEY

BPU Urges Settlement In PSE&G Upgrade Case

Public Service Electric & Gas will attempt again next week to reach a settlement with groups that oppose its $2.9 billion, five-year plan to strengthen the grid to withstand storms better. The plan is part of the company’s 10-year, $3.9 billion “Energy Strong” proposal. Some consumer groups are adamantly opposed to a settlement, arguing that a full hearing at the Board of Public Utilities would be better, and PSE&G is preparing for both. One participant in the discussions says the gap between positions is as wide as the Grand Canyon, but BPU staff urged the parties to give settlement another try.

Meanwhile, the Assembly Telecommunications and Utilities Committee approved a bill that would require the BPU to demand even tougher reliability plans and faster service restoration from utilities. The measure would impose stiff penalties for failure — up to $25,000 a day per violation, with a $2 million cap.

More: NJSpotlight (2-6-14), NJSpotlight (2-7-14)

NORTH CAROLINA

Duke Moves to Buy Muni Plant Shares

Duke Energy is negotiating to buy some generation assets from North Carolina municipal utilities, which have been burdened with the high costs of the resources for years. North Carolina Eastern Municipal Power Agency owned the assets with Progress Energy, which Duke bought in 2012. The muni group has a total of about 700 MW in several plants: the Shearon Harris and Brunswick nuclear plants and the Mayo and Roxboro coal plants. Negotiations and regulatory approvals could take up to two years.

Duke was unsuccessful in its bid to buy up to 10% of Santee Cooper’s stake in the Summer nuclear station in South Carolina. Santee Cooper ended up selling part of its stake to SCANA for about $500 million.

More: Charlotte Observer; The Wilson Times

Duke: “We apologize” For Ash Pond Spill

Stormwater drain spills ash into the Dan River (Source: Sierra Club)

“We apologize. We are accountable,” Duke Energy tweeted Friday after up to 82,000 tons of ash spilled into the Dan River. The company, already the target of state and environmental group legal action over ash ponds, said it “pledges to take care of Dan River and the surrounding environment.”

A storm water pipe under the unlined ash pond, which contained about a million tons of ash from now-retired coal units at Duke’s Dan River plant, broke Feb. 2 and gushed ash and water into the river. Disputes persisted through the week about whether the water was safe for downstream communities to use, and environmental activists renewed public pressure on the company.

The spill came shortly after the federal Environmental Protection Agency and environmental groups announced an agreement to have EPA issue long-delayed coal ash handling regulations by the end of this year.

More: Charlotte Observer; Charlotte Business Journal

OHIO

AEP Energy Savers Program Attracts 2 Cities

Louisville became the second city, after Lima, to participate in AEP Ohio’s new pilot program called Community Energy Savers. If there are 300 participants in AEP’s efficiency education and incentives program by June 30, the utility will give the city an incentive award to complete lighting upgrades at the YMCA and the old Post Office.

More: AEP Ohio

PENNSYLVANIA

Gamesa Shutdown Spurs Political Finger Pointing

The decision by wind turbine maker Gamesa to close its factory in Cambria County March 31 is a talking point for two state-office hopefuls, Democrats Katie McGinty and Mark Critz. They are blaming the shutdown on Republican Gov. Tom Corbett, who they say advocated for increased taxes on the wind energy sector and opposed bipartisan efforts to expand the state’s market for renewable energy.

McGinty, who is running for governor, is a former federal environmental official and former head of the state’s Department of Environmental Protection while Critz is a candidate for lieutenant governor.

Corbett’s office rejected the blame, saying the governor has worked with the renewable energy industry and would continue to do so to “support and sustain their growth here in Pennsylvania.”

More: The Tribune-Democrat

Lawsuit over Hatfield’s Ferry

Neighbors of the now-shuttered Hatfield’s Ferry coal-fired plant in Greene County have filed suit against Allegheny Energy Supply for what they say is heavy-metal and other pollution from the facility. They seek class-action status for the suit. The group withdrew a suit last year for what its attorney said was an attempt at mediation, but now has refiled.

More: Pittsburgh Tribune-Review

VIRGINIA

Dominion Not Giving Up On Wind Project

Although Dominion is blocked from building turbines on a ridge where it owns land intended for a wind farm, the company said it is not giving up on the project. Dominion owns 2,600 acres on East River Mountain, but has not been able to build on it since the Tazewell County Board of Supervisors enacted a ridgeline protection ordinance in 2010.

Dominion has yet to file an appeal with the appellate board established by the county to hear challenges to the ordinance.

More: Bluefield Daily Telegraph

February 10, 2014

PJM Consolidating Rules for Dynamic Transfers

PJM is consolidating its rules for establishing dynamic transfers, which allow resources in one balancing authority to be operated as if they were in another BA region. Dynamic transfers can be accomplished through pseudo ties or dynamic schedules, which are cheaper and faster (see chart).

Dynamic Schedule Vs. Pseudo Tie (Source: PJM Interconnection, LLC)

The rules, spelled out in a draft white paper, are a response to PJM’s proposed capacity import limits (ER14-503). External generators with pseudo ties and confirmed firm transmission can win exemptions from the proposed limits if they also accept a “must-offer” requirement.

“We wanted to have a central place where all the options were collected,” PJM’s Sree Yeddanapudi told members at last week’s Operating Committee meeting.

Yeddanapudi said stakeholders wishing to have input on the draft whitepaper should submit comments by Feb. 28. The paper is scheduled for final review at the Operating Committee’s March 4 meeting.

Resources planning to use pseudo ties to make capacity offers in the 2017/18 Base Residual Auction must notify PJM of their intent by May 5.

PJM Contacts:

Sree Yeddanapudi, 610-666-8991, sree.yeddanapudi@pjm.com
Dave Souder, 610-666-4795, david.souder@pjm.com

February 10, 2014January 3, 2024

Exelon May Close Nukes

Several PJM utilities released their fourth quarter earnings last week, but none made news like Exelon, which warned that it may shut down some of its nuclear generating stations if they can’t compete against subsidized renewable generators and stubbornly low natural gas prices.

“We have talked about asset rationalization in the past, and despite our best ever year in generation some of our nuclear units are unprofitable at this point in the current environment due to the low prices and bad energy policy that we are living with,” Exelon CEO Chris Crane said in a conference call.

“A better tax policy and energy policy would be the clear answer, but if we do not see a path to sustainable profits, we will be obligated to shut units down to avoid the long-term losses.”

No Hit List

Crane said there are no definite plans to shut down particular plants. Analysts, however, said some single-unit sites in Exelon’s fleet, such as Clinton Nuclear Generating Station, in Illinois, could be targeted. Another possible target is Oyster Creek Generating Station, in New Jersey, which the company already plans to decommission in 2019.

It’s not the first time Crane has mentioned shutting down plants. During the third quarter conference call last fall, he said that if wholesale prices didn’t start to rebound, Exelon could start looking at powering down some plants.

But it is the first time he’s said that units in its prized nuclear portfolio could be in the bull’s eye. Exelon traditionally has been bullish on nuclear, having built its fleet into the nation’s largest through a series of acquisitions.

Ironically, news of possible closures comes at a time when Exelon’s nuclear fleet is running better than ever. Its 10 nuclear plants in Illinois, Pennsylvania and New Jersey produced 134 million net MWh in 2013, their highest output ever, exceeding the previous record set in 2007. The plants operated at a 94.1% capacity factor.

Subsidies for renewables and slower-than-expected retirement of coal plants stacks the deck against nuclear assets, Crane said. “Our biggest push right now is at the federal and the state level to stop subsidizing in generation. That’s renewables and other sources of generation. It skews the market. It’s doesn’t give any of us the right signal — Should we be investing? Should we be shutting down? — and we think that a good policy for the competitive market is [to] let the assets compete.”

Crane’s announcement came during an analysts’ call at which the company reported an increase in fourth quarter and year-end earnings.

Fourth quarter earnings were $495 million, or 58 cents per share, compared to $378 million, or 44 cents per share a year ago. Year-end net income grew to $1.72 billion for 2013 from $1.16 billion in 2012, or $2 a share compared to $1.42 a share.

Dominion Up for Quarter, Year

Dominion Resources’ year-end earnings reports showed dramatically better numbers than a year ago, with $431 million in fourth-quarter earnings for 2013, or 74 cents a share, compared with a loss of $659 million, or $1.15 a share, a year ago.

Full-year figures showed a similar improvement, with 2013 earnings of $1.7 billion, or $2.93 per share, compared with $302 million, or 53 cents per share, a year ago.

“Dominion faced a number of challenges in 2013 and we overcame nearly all of them,” said Mark F. McGettrick, Dominion’s executive vice president and chief financial officer during a Jan. 31 earnings conference call.

Dominion’s 2012 results suffered from about $1 billion in charges associated with the sales of several fossil stations in the Midwest and Northeast, as well as a permanent shutdown of its Kewaunee nuclear plant in Carlton, Wis. and Hurricane Sandy-related restoration costs in Virginia and North Carolina.

AEP Earnings up; Ohio Revenue Eroding

AEP posted operating earnings of 60 cents per share on revenues of $3.8 billion, or a 10-cent increase over the same period last year, when it reported revenues of $3.61 billion. Year-end operating earnings were $1.57 billion, or $3.23 a share, compared with $1.5 billion, or $3.09 a share in 2012.

The fourth quarter results show a $15 million drop in operating margin at Ohio Power Co. — $590 million in 2013 compared with $605 million in 2012 — primarily from customer switching in that deregulated territory. The company said it intends to offset any continued losses in that area with increased revenue and earnings from its transmission businesses.

“Our solid financial performance in 2013, despite the loss of significant retail margins in Ohio, reflects our focus on our earnings growth strategy – investment in our core regulated operations, including our transmission business, and achieving cost savings through sustainable process improvements,” said CEO Nick Akins. “We benefited from successful regulatory proceedings in several jurisdictions, and our transmission investments delivered earnings improvement in every quarter, with transmission nearly doubling its earnings contribution in 2013.”

PPL Takes Beating on Plant Lease

PPL can blame costs associated with terminating a power plant lease in Montana for disappointing quarterly and year-end earnings, but officials said solid business unit performance offset the one-time costs.

The company’s annual profits plummeted 35% to $1.13 billion, or $1.76 a share, down from $1.53 billion, or $2.60 a share, in 2012.

Fourth quarter 2013 earnings showed a loss of $98 million, or 16 cents per share, compared with a profit of $359 million, or 60 cents per share, in 2012.

The termination of the Colstrip plant lease cost the company $413 million, or 62 cents per share, which was recorded in the fourth quarter.

Earnings from ongoing operations, which do not include the Colstrip charges, were $1.59 billion, or $2.45 per share for the year.

The company warned of lower earnings in 2014, “primarily due to lower energy margins in the Supply segment” because of lower energy and capacity prices, partially offset by lower financing costs and lower income taxes.

February 10, 2014

Transition Period OK’d for Seasonal Verification Rules

Members last week approved manual changes implementing PJM’s seasonal verification rules, adding a transition period for units that have not been conducting the required tests.

The rules require all steam generation units to correct their capacity ratings to reflect ambient temperatures. About half of PJM’s steam units already adjust their ratings although Manual 21 requires adjustments only for combustion turbines and combined cycle plants. The changes endorsed last week by the Planning and Market Implementation committees adds the correction requirements for nuclear, coal and oil units.

In addition, all hydro and pumped storage units will be required to perform verification tests during the summer. Previously, some of these generation owners were performing tests at other times of the year.

The MIC endorsed a transition mechanism that will allow generation owners options for addressing any capacity shortfalls that result from reduced installed capacity (ICAP) ratings under the corrected measurements.

Generation owners will have the option of seeking a capacity modification, and covering their deficiency with other assets or capacity purchases, or seeking forgiveness for shortfalls and relinquishing capacity revenues for the shortfall.

PJM sought an April 1 deadline for generation owners to make their choice for their entire portfolio.

“This was [suggested] in recognition that some generation owners are already providing adjusted results, while others haven’t,” said Stu Bresler, vice president of market operations.

Bresler resisted a request to allow generation owners to make decisions on individual units rather than their entire portfolios. “Our thought was we’d make it a one-time election,” he said. “It may seem inequitable to let GOs pick and choose what adjustments best suit them.”

Under a “friendly amendment” accepted by PJM, owners will have until April 1 for units providing capacity in delivery year 2014/15; June 1 for capacity for DY 2015/16 and Aug. 1 for DY 2016/17.