Members Deadlock on Change to $1,000 Offer Cap

PJM stakeholders deadlocked Thursday over changes to the $1,000 energy offer cap, leaving the RTO’s board considering yet another unilateral filing with the Federal Energy Regulatory Commission.

None of three proposals considered by the Markets and Reliability Committee won a two-thirds majority.

The primary proposal from the Cap Review Senior Task Force (proposal B), which would have eliminated the cap for cost-based offers and let them set LMPs, won only 42% support in a sector-weighted vote of the MRC, with unanimous opposition from the Electric Distributor and End Use Customer sectors.

The proposal would have limited cost-based offers to production cost plus a 10% adder for unquantifiable costs. Market-based offers would be limited to the cost-based offer or the cap on 30-minute demand response ($1,849/MWh for delivery year 2015-16), whichever is more.

A revised version of that proposal that would maintain the cap on market-based offers also failed with 42%.

An alternative by the Delaware Public Service Commission (proposal A), which would have allowed cost-based offers above $1,000/MWh but would not have allowed them to set LMPs, also fell short at 61%. The proposal won unanimous support from the ED and EUC sectors and almost 60% of Other Suppliers, but it received less than 30% of Transmission Owners and Generation Owners. (See voting report.)

In January, FERC granted the RTO’s request for a waiver allowing make-whole payments for generators with operating costs more than $1,000. PJM said the waiver was necessary to allow some gas-fired generators to cover marginal costs that hit $1,200/MWh in late January, as spot gas prices spiked as high as $140/mmBtu. The January order allowed PJM to fund the make-whole payments through uplift charges. In February, FERC granted a second waiver eliminating the cap through March 31, allowing high-cost generators to set LMPs.

One-Sided Debate

While generators’ representatives were curiously silent before the votes, load representatives were vocal in their opposition to eliminating the offer cap, which they said was necessary to counter market power and ensure generators operate efficiently.

“Our members have a strong desire to retain the cap as it is,” said Dan Griffiths, executive director of the Consumer Advocates of PJM States.

Walter Hall of the Maryland Public Service Commission said there were only a few generators — reliant on gas supplies from constrained pipelines — that claimed costs exceeding $1,000/MWh in January. “You’re really just importing market power from the natural gas industry into the electric industry,” Hall said. “We think that’s inappropriate.”

John Farber of the Delaware PSC said there was little evidence of the need to lift the offer cap. “It’s yet to be proven that there is a boogey man in the closet,” he said.

Farber said his proposal ensured that no generator would be forced to operate at a loss while preserving the “circuit breaker” of the current cap by ensuring generators with lower costs don’t receive a windfall from higher LMPs.

Susan Bruce, representing the PJM Industrial Customer Coalition, said her group was supporting the Delaware proposal “in the spirit of compromise and in the interest of having one less [disputed] issue before FERC.”

David “Scarp” Scarpignato of Direct Energy said offers exceeding $1,000 should set LMPs. “We don’t believe actual costs should go into uplift,” he said. “It’s unhedgeable. That’s a really bad deal for a load-serving entity.”

One More Try

When the last of the three votes failed, PJM’s Adrien Ford declared the task force’s work done. Andy Ott, executive vice president for markets, indicated that PJM’s Board of Managers would consider a unilateral Section 206 filing with FERC. “We do have to move forward if the group can’t reach consensus,” he said.

But Ed Tatum of Old Dominion Electric Cooperative said stakeholders should make a last-ditch effort to reach compromise before the next Members Committee meeting Oct. 30. “We need to have a Section 205 [consensus] filing,” he pleaded.

PJM CEO Terry Boston also urged members to reach consensus. “There is a limit on how many issues we can dump on FERC between now and Dec. 1,” he said. “I don’t think FERC is going to respond kindly if we keep bringing 206 disagreements.”

The task force, which had been slated for sunsetting, will instead meet at 1 p.m. Oct. 10 to consider its options.

September 23, 2014June 15, 2023

Federal Briefs

The Government Accountability Office expects 13% of the nation’s coal-fired generating capacity to retire between 2012 and 2025, an increase from the 2% to 12% range the GAO predicted two years ago.

At the same time, the GAO is reducing its forecasts for coal capacity receiving retrofits to meet Environmental Protection Agency emission regulations to 70 GW, down from its previous forecast of 102 GW.

About 38% of the total 42.2 GW expected to retire are in four PJM states: Ohio (14%), Pennsylvania (11%), Kentucky (7%) and West Virginia (6%), according to the GAO report released last week.

In a 2012 report, the GAO called for the EPA, the Department of Energy and the Federal Energy Regulatory Commission to develop a formal, joint process for monitoring the electric industry’s response to EPA regulations.

The new report said the agencies have taken steps to implement the recommendation, including regular joint meetings with RTO officials and other stakeholders.

The new report, requested by Alaska Sen. Lisa Murkowski, the ranking Republican on the Senate Energy and Natural Resources Committee, makes no additional recommendations.

Senate Confirms 2 for US NRC Posts

The Senate last week confirmed two nominees to the Nuclear Regulatory Commission, bringing the commission to full strength. Jeffrey Baran, aide to Rep. Henry Waxman (D-Calif.), and Stephen Burns, a former NRC general counsel, were confirmed with votes that generally fell along party lines.

Baran replaces Bill Magwood, who has accepted a position with the Paris-based Nuclear Energy Agency. He will finish Magwood’s term, which expires June 30, 2015. Burns will replace George Apostolakis, who left June 30 after the White House did not re-nominate him. Burns’ term will run through June 30, 2019.

More: The Wall Street Journal (subscription required)

EPA to Accept Comments on Carbon Rule Until Dec. 1

The Environmental Protection Agency has extended the comment period on its proposed carbon emission rule for 45 days to Dec. 1.

“We’ve got a number of requests from a variety of stakeholders that they would like more time,” Janet McCabe, acting assistant administrator for the Office of Air and Radiation, said in a press conference Tuesday.

The rule, which would affect existing power plants, is intended to cut carbon emissions from the power sector 30% below 2005 levels when it is fully implemented in 2030. The agency has received about 750,000 comments so far. McCabe said the expanded comment period would not affect plans to finalize the rule by June 1, 2015.

More: EPA

White House Threatens Veto on Energy Bill Package

The Obama Administration last week threatened to veto a package of Republican-sponsored House bills that include expanding offshore drilling, approval of the Keystone XL pipeline and expedited approval of liquefied natural gas exports.

Republicans passed the proposals in a move to emphasize their stance against President Obama’s energy policies. But the White House said the bills “would roll back policies that support the continued growth of safe and responsible energy production in the United States” and run contrary “to the administration’s commitment to promoting safe and responsible domestic oil and gas development.”

More: The Hill

Consumers Energy Reaches Accord with EPA and Justice Department

Michigan’s Consumers Energy will spend more than $2 billion on emissions-control upgrades at Michigan power plants as part of an agreement with the Environmental Protection Agency and the Department of Justice. The settlement comes at the end of five years of negotiations between the parties.

The EPA in 2007 and 2008 alleged that the company violated opacity regulations and operated some plants without necessary permits or that required emissions-control equipment. The company also agreed to pay a $2.75 million civil penalty.

The company also agreed to retire seven of its oldest coal-fired power plants: three units at the J.R. Whiting Generating Complex near Luna Pier; two at the B.C. Cobb Generating Plant in Muskegon; and two at the Karn/Weadock Generating Complex near Bay City, with a combined capacity of 950 MW.

More: PennEnergy

NRC Approves Use of New Reactor for North Anna

The Nuclear Regulatory Commission has approved GE-Hitachi Nuclear Energy’s Economic Simplified Boiling Water Reactor design for a proposed third unit at Dominion Virginia Power’s North Anna nuclear power station. The NRC approval means that the reactor design meets safety requirements for use in the U.S.

The NRC’s OK was part of the design approval and construction permitting process for the Virginia utility. Dominion says it expects to receive necessary approvals in 2016 for North Anna 3, although it has not yet decided whether to build the unit.

The NRC’s approval brought some criticism. “No reactor is earthquake-proof, and Dominion has no business building another reactor on an active fault line,” said Glen Besa, director of the Sierra Club’s Virginia chapter. North Anna’s two 980-MW reactors were out of service for three months after a 5.8-magnitude earthquake in 2011. A comprehensive inspection concluded the plant suffered no damage.

More: The News & Advance

US Gas Production Keeps on Rising

Natural gas production in the U.S., bolstered by shale-gas drilling, continues to increase steadily. A report by Bentek Energy estimated that production increased 0.4 billion cubic feet per day from July to August. Bentek says production set a record of 69.04 billion cubic feet per day on Aug. 29, eclipsing a record set the previous month.

“The U.S. continues to break natural gas production records almost on a daily basis,” said Jack Weixel, Bentek’s director of energy analysis. August was the eighth consecutive month of production increases. Compared to August last year, natural gas production was up 6%.

More: PennEnergy

Sherwood-Randall Confirmed as DOE Deputy Secretary

The Senate confirmed the appointment of Elizabeth Sherwood-Randall to the No. 2 post at the Department of Energy last week.

Sherwood-Randall was President Obama’s adviser on nuclear weapons and arms control since 2013. Before that, she was his European affairs adviser. She will replace Daniel Poneman, who stepped down as deputy secretary in June after five years.

“Liz’s confirmation comes at a historic time in our nation’s energy evolution,” Energy Secretary Ernest Moniz said. “She joins us with deep expertise in the department’s nuclear security mission, including both nuclear weapons and countering proliferation.”

More: The Hill

DOE Report Finds No Water Woes from Fracking

A Department of Energy report that tested water wells near a natural gas drilling site that was hydraulically fractured found no evidence that fracking had contaminated groundwater. The study, released last week, found that no chemicals used in the fracking process had migrated to six test water wells at a Pennsylvania site.

Critics said the study was too small to prove that fracking is safe. They called for tighter regulation of drilling until a final determination is made.

More: ABC News

September 23, 2014

PJM to Generators: Provide Operating Parameters in Writing

PJM will revise its eMKT application to capture more detailed information and require generation owners to use it to verify their operating parameters under a proposal outlined to members last week.

Generation owners will be required to ensure all data in eMKT is accurate, particularly notification times, minimum run times, unit status and unit limits (emergency and economic min & max).

PJM will also require owners to make all updates in eMKT, and operators will use only that data for unit commitment decisions. Verbal notifications will be permitted only if previous unit commitments cannot be met or a unit trips or encounters other problems in real time.

“We want to get away from all the phone calls and changing information in real time,” said PJM’s Chantal Hendrzak, who presented the proposal to the Markets and Reliability Committee Thursday. “We want to be able to pull that information out of eMKT.”

Among the additional information that PJM will be requiring are details on units’ dual-fuel capabilities (e.g., time to transition, megawatt output during transition) and operational restrictions (e.g., emissions limits).

Generators would also be able to update their energy offers and cost-based start-up and no-load costs during the operating day to reflect gas-price volatility.

The proposed changes are expected to be brought to an Operating Committee vote next month.

September 23, 2014

Market Monitor on Talen Plan: Not So Fast

By Ted Caddell

PPL’s plan to spin off its generation needs additional mitigation to address local market power concerns, PJM’s Independent Market Monitor told the Federal Energy Regulatory Commission last week.

PPL and Riverstone Holdings announced in June they would join their generation businesses into a publicly traded independent power producer named Talen Energy. The new company would own 15,320 MW of capacity, including 12,000 MW in PJM.

In their application to FERC (EC14-112), the companies proposed selling about 1,300 MW of PJM generation to avoid market power complaints. The companies said that no company with more than 10% of PJM’s summer installed capacity would be permitted to bid for the plants. That would leave out Public Service Enterprise Group, Exelon and NRG Energy. (See PPL, Riverstone ID Plants for Sale in Talen Spinoff.)

Not Enough

The Market Monitor told FERC that isn’t enough.

“The transaction, even with the applicants’ proposed mitigation, would have an anticompetitive impact,” the Monitor’s analysis says.

“The analysis concludes that the transaction would significantly increase concentration in specific, highly concentrated locational energy markets, would increase concentration in the capacity market and would have minimal effect on the market for regulation.”

The Monitor said “behavioral mitigation” would level the playing field.

It recommended that FERC:

Require Talen to make cost-based offers in the energy and regulation market.
Require Talen to offer the same plants and output as PPL did, prohibiting it from holding back generation to drive prices up.
Expand the list of companies barred from purchasing the plants sold in mitigation to include American Electric Power, FirstEnergy, Dominion Resources, Duke Energy and Calpine. (Editor’s Note: The IMM said its initial filing, which was referenced in an earlier version of this story, erroneously included Edison International and failed to include Duke).

PPL questioned the IMM analysis and said it remains confident of FERC approval.

“PPL believes that the mitigation proposal addresses completely any potential FERC issues with concentration of power generation assets within PJM,” spokesman George Lewis said. “On first read, PPL believes the IMM’s comments are not justified by the facts of the PPL-Riverstone combination. We will review the comments in greater detail and respond at FERC.”

Allegheny Protest

The Monitor was not the only party to challenge the PPL-Riverstone deal. Allegheny Electric Cooperative, which owns 10% of the Susquehanna nuclear plant that is part of the spinoff, told FERC that it was blindsided by the deal and has not received assurances that the new owners are qualified to run a nuclear plant.

Allegheny said it first heard of the Talen deal late on the night of June 9, when PPL and Riverstone announced it.

“Even though Allegheny is a co-owner of and co-licensee for Susquehanna, PPL did not advise or provide any information to Allegheny concerning the proposed transaction until the proposed transaction was publicly announced,” the company wrote in its protest to FERC.

“The filing does not explain how PPL is complying with its contractual obligations to Allegheny regarding the operation and maintenance of Susquehanna in transferring its interests in the facility to Talen Energy,” Allegheny wrote in its protest. “Further, it fails to describe Talen Energy’s competence in owning, operating, maintaining and providing for the overall management of a facility as important to the region — both in terms of power supply and reliability — as Susquehanna.”

Lewis wouldn’t directly address the Allegheny complaints. “We are reviewing those as well and will provide a response at FERC,” he said.

In a July filing asking the Nuclear Regulatory Commission to approve the transfer of Susquehanna’s license, PPL said the spinoff will have little impact on plant operations. “The proposed transaction will not result in any undue risk to public health and safety and will not be inimical to the common defense and security,” PPL wrote.

September 23, 2014

Two of 4 Artificial Island Finalists Offer Cost Caps

Two of the finalists for the Artificial Island transmission fix have offered to cap their costs while a third has teamed up with Pepco Holdings Inc. in a bid to improve its chances.

In July, PJM’s Board of Managers delayed action on planners’ recommendation that it select Public Service Electric & Gas to address stability problems at Artificial Island at a cost of $211-$257 million. The board told PSE&G and finalists Transource Energy and Dominion Resources to “supplement” their proposals in response to finalist LS Power’s offer to cap its project cost at $171 million. (See PJM Board Puts the Brakes on Artificial Island Selection.)

In response, PSE&G offered to cap its price at $221 million and LS Power reduced its cap to $146 million.

Dominion declined to provide a cost cap but revised its estimate for one proposal to $174 million, including a 10% contingency for construction and a 50% contingency for real estate and permitting.

Transource, which also declined to agree to a cost cap, revised its estimated cost to $203 million, excluding work required at the Salem station and a $52.3 million contingency. The company, which had previously estimated its project at $165 million to $208 million, said its revised estimate reflected the need to employ specialized drilling techniques and the addition of a second underwater cable.

Transource said it would forego 50% of any return-on-equity incentives on any costs between $203 million and $255.3 million and 100% of the ROE incentives on any costs exceeding $255.3 million.

Transource also disclosed that it had signed a memorandum of understanding with Pepco, parent of Delmarva Power & Light, to partner on the project. “This arrangement significantly improves the likelihood of project success based on PHI/Delmarva’s significant experience working in the project area, familiarity working with the numerous permitting agencies and on‐the‐ground resources to provide operations and maintenance services over the life of the project,” Transource said.

FERC Oversight

The board delayed action on staff’s recommendation of PSE&G following criticism over planners’ decision to eliminate two 500-kV lines from the company’s original $1.066 billion proposal.

Seeking to avoid additional controversy, the board also asked the Federal Energy Regulatory Commission to appoint an administrative law judge to serve “in a non-decisional role to ensure the fairness and due process” regarding PJM’s discussions with the finalists.

ALJ Steven Sterner will attend meetings between PJM and the finalists or review agendas and proposed questions to “ensure that PJM’s line of inquiry is consistent with each of the bidders and that no bidder is given an undue advantage in their presentation to PJM,” the RTO said in an Aug. 29 letter to Chief ALJ Curtis Wagner.

Sterner “will observe and comment upon … the fairness of the process undertaken by PJM through these final negotiations but not attempt to influence PJM staff’s substantive recommendation or the final PJM board decision in any way.”

PJM will not be required to follow the judge’s recommendations.

September 23, 2014

FERC, New York PSC to Meet on Capacity, Regulatory Reform

By William Opalka

The Federal Energy Regulatory Commission and New York regulators will hold a joint technical conference Nov. 5 to discuss the state’s capacity market and plans to revamp the utility business model to accommodate renewable energy and distributed resources.

FERC’s conference with the New York Public Service Commission will be held from 9:30 a.m. to 5 p.m. at the New York Institute of Technology in Manhattan.

Reforming the Energy Vision

One focus of the conference will be the PSC’s Reforming the Energy Vision (REV) initiative, which the commission announced in April.

The PSC noted that technological innovation and the increased competitiveness of renewable energy and distributed resources is occurring as the state confronts aging infrastructure, extreme weather events and challenges to system security.

FERC Chairman Cheryl LaFleur said the commission wants to learn about how the REV program intends to reform the state’s energy industry and regulatory practices to meet these challenges.

“The New York PSC and New York leadership have produced some interesting things around their REV … that would potentially require evolution in the role in some of the things that we’re looking for from the ISO,” she explained after announcing the technical conference at last week’s FERC meeting.

The PSC released a straw proposal in August that found “There is large potential for the integration of Distributed Energy Resources (DERs) into the New York electricity market, via a Distributed System Platform (DSP) framework.”

The report outlined potential reforms in the utility ratemaking process “to provide the correct incentives for utilities and markets to develop a cleaner and more efficient electric system.”

A two-track public proceeding is examining the regulatory reforms. The first track examines the role of distribution utilities in deploying distributed energy resources to promote load management and system efficiency, including peak load reductions. The second, parallel track will consider changes in tariff and market designs and incentives to align utility interests with the policy objectives.

Public comment on the proposal was due yesterday.

Capacity Zone Controversy

The Nov. 5 conference will also be something of a fence-mending effort for FERC, following its approval of a controversial capacity zone intended to address transmission congestion north of New York City.

Opponents claim the zone, which took effect May 1, will create a windfall for existing generation owners before the region’s constrained supply issues can be full addressed.

In July, New York Sens. Charles Schumer and Kirsten Gillibrand voted against the reconfirmation of LaFleur, a fellow Democrat, to FERC. Before the vote, Majority Leader Harry Reid (D-Nev.) said he had spoken to LaFleur about the criticism of the capacity zone and that she had agreed to “take a hard look at” it. (See New Yorkers Upset over NYISO Capacity Zone.)

LaFleur Thursday acknowledged the controversy over FERC’s approval of the zone. “Those orders are final but it seemed like it might be a good time to consider: Is the capacity market attracting the investment we need for reliability? Let’s have a refresher on where we are,” she said.

September 23, 2014June 15, 2023

State Briefs

PSC Gives Go-Ahead for Out-of-State Tx Ownership

The Public Service Commission has ruled that out-of-state companies can build and own transmission lines in the state, clearing the way for PJM to move forward with a solicitation process to upgrade lines delivering power from New Jersey’s Artificial Island nuclear complex. (See related story, Two of 4 Artificial Island Finalists Offer Cost Caps.)

The PSC’s opinion clarifies ambiguities in state law. One of four companies seeking to upgrade the transmission lines, Northeast Transmission Development, asked the PSC to make a determination.

PJM’s effort to upgrade the lines is the first time the transmission operator used FERC’s Order 1000 solicitation process, but it advised the four project finalists to seek a PSC opinion to resolve the legal uncertainty.

More: The News Journal

INDIANA

Court Rules Duke Fees for Gas Plant Wrong

The Court of Appeals has ruled that state regulators should not have allowed Duke Energy to recover $61 million from customers for costs of building the Edwardsport coal gasification plant. The court ruled that the Utility Regulatory Commission didn’t conduct a comprehensive analysis before awarding the fees to Duke.

More: The Indianapolis Star

MARYLAND

Exelon Facing Mounting Demands for Approval of Pepco Takeover

A group wants half of Pepco’s profits to be linked to performance standards in exchange for approval of its planned merger with Exelon.

The newly formed Coalition for Utility Reform wants the Public Service Commission to require “half of the merged entity’s profit to be determined by its ability to meet standards related to cost minimization, reliability, customer satisfaction, carbon reduction and environmental stewardship, distributed energy resources, customer control, and innovation.”

“This broad coalition recognizes that the current utility system is broken,” said Montgomery County Councilmember Roger Berliner, who filed the petition. The coalition plans to become an official intervener in the case.

Another group called PowerUpMontCo is asking for “a multi-billion dollar investment of capital into the infrastructure to bring Pepco’s long-neglected and dilapidated distribution system up to top-quartile service performance levels.”

Pepco shareholders are meeting to vote on the merger today.

More: BethesdaNow; The Washington Post

Woman Challenges Pepco on Meter Charge Issue

A retired attorney from Chevy Chase is challenging Pepco’s rules requiring customers who don’t want a smart meter to pay a charge.

Deborah A. Vollmer, who fears that smart meters cause health problems and a loss of privacy, has refused to pay the opt-out fees. Pepco charges customers who decline a smart meter a $75 up-front fee plus $14 month. About 1,060 customers have declined to get the meters installed, but Vollmer is the only one who refused to pay.

Jonathan Libber, president of Baltimore-based Maryland Smart Meter Awareness, likened the opt-out fees to “protection money” that businesses pay to the mob. The organization seeks to educate the public about the potential dangers of smart meters and wireless devices generally.

More: The Gazette

NEW JERSEY

Christie Names 2 to BPU Posts

Richard Mroz (Source: University of Delaware)

Gov. Chris Christie named a Republican attorney and longtime friend as president of the Board of Public Utilities last week.

Richard Mroz, former chief counsel for Gov. Christine Whitman’s administration, would replace Dianne Solomon as head of the five-member board. Christie and Mroz were classmates at the University of Delaware. Christie previously named him to the Delaware River & Bay Authority in 2012.

Christie also nominated seven-term state Assemblyman Upendra Chivukula to fill a vacancy on the BPU. Chivukula, a Democrat, would step down from the legislature if confirmed to the utilities board.

The state Senate is expected to act on the nominations this week.

More: NJ.com

NORTH CAROLINA

Coal Ash Law Goes in Effect Without McCory’s Signature

A new law requiring more stringent management of coal-ash ponds at power plants went into effect last week without Gov. Pat McCrory’s signature.

Lawmakers approved the bill last month in response to public uproar after a dam at one of Duke Energy’s coal ponds failed earlier this year, spilling 39,000 tons of ash into the Dan River. State law calls for the governor to either sign the law or veto it within 30 days.

McCrory, a former Duke employee, did neither. The governor said he thinks the bill violates his power and the state constitution and that he will ask the state’s Supreme Court to review it.

More: Greensboro News & Record

OHIO

DPL Sells Share of Plant to Duke Energy Kentucky

The Public Utilities Commission approved Dayton Power and Light’s plans to sell its 31% share of the 650-MW East Bend coal-fired power plant to Duke Energy Kentucky. PUCO agreed that the transaction will allow both utilities to better serve their customers.

Duke Energy will be sole owner of East Bend, giving it a hedge against the 2015 retirement of its 163-MW plant at Ohio’s Miami Fort Station. The sale needs the approval of the Kentucky Public Service Commission, which is expected by the end of the year.

More: Utility Dive

AEP Spending $21M on Tx Upgrades for Shale Gas

American Electric Power plans a $21 million transmission-system upgrade to provide more power to two large oil and gas pipeline companies that are expanding operations in the state’s shale-gas region. The Public Utilities Commission has approved the project, which will upgrade the 69-kV line in Jefferson and Harrison counties to 138-kV.

AEP says it is responding to requests for more power from M3 Midstream and Access Midstream Partners. Shale-gas drilling has increased demand for electrical power at a rate unseen in the past.

“Most industrial load you can plan 18 to 24 months in advance,” said Dan Recker, AEP’s managing director of transmission engineering. “This is much faster than that. They were needing [electric] service in weeks instead of several months, and that really presented some challenges from a process standpoint.”

More: Columbus Business First

PENNSYLVANIA

PUC Approves PPL’s New Time-of-Use Program

The Public Utility Commission has approved PPL’s pilot time-of-use program that is aimed at inducing customers to shift their energy use to off-peak hours to help meet the state’s energy-efficiency mandates.

The PUC approved PPL’s plan, which allows customers to sign up with third-party suppliers to get electricity at rates that adjust between off-peak and on-peak hours. The plan goes into effect Dec. 10.

The time-of-use rates should help PPL to comply with Act 129, a 2008 law that requires the state’s largest electric distribution companies to develop conservation plans to reduce consumption and shift load from peak hours.

More: Lehigh Valley Business

Pike County L&P, PUC Agree on New Rates

The Public Utility Commission approved a settlement allowing Pike County Light & Power to increase revenue by 12.8% or $1.25 million, less than the $1.7 million the company originally sought.

The boost will increase rates for a typical residential customer by 16.2%, or from $93.06 a month to $108.10. The company has about 4,600 customers in Pike County in Northeastern Pennsylvania.

More: Public Utility Commission

VIRGINIA

Utility’s Plan for Surcharge Irks Home Solar Customers

Appalachian Power’s plans to assess a fee on residential customers who have solar power systems has irked renewable power advocates.

The utility’s “standby charges” would cost customers with solar or wind systems connected to the grid about $3.77 per kilowatt per month. The fee would apply only to customers with systems rated between 10 kW and 20 kW, fairly large by residential standards.

State law allows for the charges if a utility can justify them, but some argue that Appalachian hasn’t proven its case. Appalachian says that customers with larger solar power systems are benefitting from the grid but aren’t paying to maintain the system.

More: The Roanoke Times

September 17, 2014June 15, 2023

FERC Commissioners at Odds over ISO-NE Capacity Auction

Clark, Bay Would Throw Out Results

The Federal Energy Regulatory Commission yesterday called for changes in ISO-NE’s capacity market rules, but split over whether it should reject the results from the ISO’s February auction due to unchecked market power.

Republican Tony Clark and Democrat Norman Bay called for FERC to reject the auction results, but Chairman Cheryl LaFleur and Republican Philip Moeller said the commission should seek only prospective changes in the auction rules. Because of the 2-2 deadlock, the 2017-18 auction results “became effective by operation of law” (ER14-1409).

In a separate docket (EL14-99), the commissioners unanimously ordered the ISO to defend its current auction rules or submit Tariff revisions creating a process for reviewing importers’ capacity offers and mitigating any market power. The commission set a 30-day deadline for the ISO’s response.

$3 Billion

The ISO’s eighth Forward Capacity Auction (FCA) resulted in a sharp price increase after nearly 3,000 MW of capacity submitted retirement requests. Fearing they would have less capacity offered than required, ISO-NE officials applied administrative price rules to the auction.

New resources in the Maine, Connecticut and Rest-of-Pool Capacity Zones will be paid $15/kW-month while existing resources in those zones will receive an administrative price of $7.025/kW-month. Both new and existing resources in the NEMA/Boston Capacity Zone will be paid $15/kW-month.

The ISO said total capacity costs for 2017/18 would be $3.05 billion, almost double the previous high ($1.77 billion in 2009).

Unlike other RTOs, ISO-NE’s capacity auction results are subject to commission review under the just and reasonable standard — the result of a 2006 settlement to address stakeholder concerns over the market design.

Clark and Bay issued a joint statement saying the auction results should be rejected and the matter set for a fast-track hearing and settlement procedures.

“Here, there is evidence suggesting the exercise of market power, and it is uncontroverted that the market power, if it existed, was not mitigated,” Clark and Bay said. “Moreover, it is possible that ISO-NE may have violated its Tariff in the way it conducted the auction. On this record, we do not believe that ISO-NE has carried its burden of establishing that the auction results are just and reasonable.”

LaFleur and Moeller said they would have approved the auction results because the ISO followed the rules previously judged just and reasonable.

“My objecting colleagues raise a valid point, that is, can an auction process that has previously been found to be just and reasonable produce results that are not just and reasonable? While such circumstances are not common, the answer is most certainly yes,” Moeller said in a statement. “However, in this case, while the prices resulting from FCA 8 were much higher than in prior auctions, the existence of very tight supply and demand fundamentals are primarily responsible for the FCA 8 results.”

After-the-Fact Ratemaking

In her statement, LaFleur said Clark and Bay’s position — that the commission not only determine whether the auction rules were followed but also assess whether the resulting rates were just and reasonable — would violate commission precedent and subject auction participants to “regulatory uncertainty or after-the-fact ratemaking.”

“I believe that respecting the established expectations of market participants as to the operation of the auction will be critical to the future ability of the FCM [Forward Capacity Market] to attract resources needed for reliability,” LaFleur said. “If market outcomes are accepted during times of excess capacity when the auction clears at the price floor, but the commission-approved auction rules are subject to retroactive revision when capacity is tight and market capacity prices are high, the long-term viability of the market is undermined.”

Even if the commission had authority to retroactively change the auction rules, LaFleur said, “The alternative approach begs the question of how to set the auction rates. Upon rejecting the existing, commission-approved auction rules, the alternative approach offers no guidance for establishing a just and reasonable replacement rate. This would be true whether the new rate were to be established by ISO-NE, the commission or a judge, because the only way to obtain a different rate is to change the underlying auction rules.”

Clark and Bay said LaFleur’s position “renders illusory the commission’s prior assurance [in approving the 2006 settlement] it would undertake a ‘thorough review of the final auction clearing prices.’”

“This alternative theory, to which we cannot subscribe, requires the commission to ignore the clear terms of the FCM settlement which the commission itself approved, and also requires the commission to accept as a fait accompli whatever price outputs are generated from the auction,” they wrote. “Under such a theory, not even allegations of unmitigated exercises of market power, nor referrals by a market monitor, could be taken into consideration by this commission, no matter the harm imposed on consumers.”

Unlike the first seven auctions, New England faced a capacity shortage entering FCA 8 after 3,135 MW of capacity, including the 1,535-MW Brayton Point generator, sought to retire before delivery year 2017-18. The retirement announcements came after the qualification deadline for new resources seeking to participate in the auction.

Instead of an expected surplus of more than 2,000 MW, the ISO went into the auction more than 1,000 MW short of its net Installed Capacity Requirement.

The ISO acknowledged that in “situations with limited excess supply, participants with a large amount of that supply are likely to recognize that they can be pivotal and set the auction price. Indeed, participants [in FCA 8] may have already been aware of the situation due to the publicly available information provided prior to the auction.”

Order to Show Cause

The commission’s Order to Show Cause is focused on rules specifying the Independent Market Monitor’s authority for reviewing offers from capacity imports.

The ISO’s Tariff requires its IMM to review import offers and reject any that the Monitor determines “may be an attempt to manipulate” the auction.

The commission said the Tariff limits the review to the qualification process, “and it only involves ensuring that the behavior of import resources was consistent with their actions in previous FCAs, rather than evaluating the bids of import resources for consistency with their net risk-adjusted going-forward costs, as is done for the offers of other resources.”

“Given the changing balance of supply and demand in New England,” the commission said, that provision “may be insufficient to ensure just and reasonable rates.”

September 16, 2014

MRC/MC Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:30)

Members will be asked to endorse the following manual changes:

Manual 11: Energy & Ancillary Services Market Operations and Manual 15: Cost Development Guidelines will be revised to correct a typographical error. The words “mileage ratio” will be replaced with “mileage” in Section 3.2.7 of Manual 11 and Section 2.8 of Manual 15, where the calculation of adjusted regulation performance cost is described. There is no change in PJM’s calculations, which have been correctly using mileage as it is defined by PJM.
Manual 14A: Generation and Transmission Interconnection Process will be revised with the addition of a new section 1.14 regarding interim deliverability studies.
Manual 14D: Generator Operational Requirements will be updated as part of an annual review and include changes reflecting North American Electric Reliability Corp. standard MOD-025-2.
Manual 18: PJM Capacity Market will be amended to include details of the processes regarding maintenance outages for Annual Demand Response.

3. FTR/ARR Senior Task Force (FTRSTF) Problem Statement, Issue Charge and Charter (9:30-9:40)

Members may be asked to vote on changes in the scope of the Financial Transmission Rights Senior Task Force. The task force was formed to evaluate the causes for FTR underfunding and determine whether the current FTR and auction revenue rights processes to improve FTR funding levels. The proposed changes include an examination of the role of virtual transactions on revenue adequacy and proposed solutions by the Market Monitor.

4. Credit subcommittee Items (9:40-10:00)

Members will be asked to approve the following changes recommended by the Credit Subcommittee. The changes were approved by the Market Implementation Committee Sept. 3:

Risk Documentation Requirements – Remove the requirement that officer certifications be notarized and allow electronic submissions. Eliminate the requirement for annual submissions of risk policy documentation; PJM will accept certification that no substantive changes have been made since the last submission.
Peak Market Activity (PMA) Exclusions – Spot market energy, transmission congestion and transmission loss charges resulting from virtual transactions will be excluded from the peak market activity (PMA) credit requirement. Virtual transactions have their own credit screening rules. Screened export transactions also will be excluded from the PMA. The PMA is used to set baseline credit requirements for members based on historical activity.
Virtual and Export Transactions Credit Requirement Timeframe – Reduce the credit requirement timeframe for export transactions to two days from four days. The MIC approved a similar change in August for virtual transactions. (See PJM MIC OKs Settlement, Credit Changes.)
Demand Bid Volume Limits – PJM will establish a daily demand bid limit for each load-serving entity by transmission zone. Bids would be limited to the LSE’s calculated zonal peak load reference point for the day plus whichever value is more, 30% of the reference point or 10 MW. The 30% limit was based on analysis showing that the largest two-day-ahead zonal forecast shortfall from January 2013 through March 2014 was 28%.

PJM said the need for such limits was illustrated by the default of People’s Power & Gas in January. Due to an input error, the company entered a demand bid about 100 times the retailer’s load. Because demand bids are currently unlimited, bids exceeding actual load act as a decrement bid but lack the protections of the virtual transaction credit screen and minimum participation requirement.

5. Cap Review Senior Task Force (CRSTF) (10:00-10:30)

Members will vote on proposed changes to the $1,000 energy market offer cap.

Cost-based incremental energy offers would be limited to production costs as defined by Cost Development Guidelines plus 10% with no cap. Market-based offers would be limited to the greater of the cost-based offer or the offer cap for 30-minute notice demand response. Adders for frequently mitigated units (FMUs) and associated units (AUs) would not apply above $1,000/MWh. Market-based offers must be less than or equal to cost-based offers when cost-based offers are greater than the 30-minute DR offer cap.

The proposal won 63% support at the Cost Review Senior Task Force. If it does not win a two-thirds vote at the MRC, members may vote on an alternative proposal by Old Dominion Electric Cooperative and the Delaware Public Service Commission. It would allow offers above $1,000/MWh during Maximum Emergency Generation Alerts but would not allow the offers to set LMPs.

Members also will consider sunsetting the task force.

6. Capacity Senior Task Force (CSTF) (10:30-10:45)

Members will consider a proposed transition mechanism related to changes requiring more operational flexibility from DR providers. The change would allow curtailment service providers to designate previously cleared megawatts as “non-viable” — unable to meet the 30-minute-lead-time requirement. CSPs would be relieved of their obligations and have their capacity payments reduced.

The transition mechanism was developed to comply with the Federal Energy Regulatory Commission’s May 9 ruling on the DR changes (ER14-822).

Members also will consider sunsetting the Capacity Senior Task Force.

7. RPM: Capacity Import Limits – CTRs and ICTRs (10:45-11:00)

Members will vote on a problem statement and issue charge proposed by H-P Energy Resources to consider allowing qualifying transmission upgrades (QTUs) for capacity import limits. PJM instituted the limits on capacity imports in the May 2014 Base Residual Auction. (See Major Rule Changes Reduced Imports, DR.)

QTUs are currently allowed to increase the Capacity Emergency Transfer Limit (CETL) into locational deliverability areas (LDAs).

8. Transparency of TO Calculations (11:00-11:10)

Members will consider closing an issue relating to the transparency of the calculations transmission owners use for allocating energy, capacity and transmission costs. PJM has created a webpage listing the methodologies transmission owners use for calculating total hourly energy obligations (THEO), peak load contributions (PLC) and network service peak loads (NSPL).

The issue arose because some TOs have not filed tariffs disclosing the methodology they use. Some members complained that the lack of transparency made it difficult to ensure they were being properly charged. (See TOs Will Disclose Calculation Methodologies.)

Members Committee

2. CONSENT AGENDA (1:20-1:25)

Members will consider proposed revisions to the Operating Agreement clarifying the definition of supplemental transmission projects. Under the proposed revision, a supplemental project is one that is not a state public policy project and is not required for system reliability, operational performance or economic criteria.

The change removes a reference to supplemental projects as “Regional RTEP” (Regional Transmission Expansion Plan) projects. It also clarifies that any reliability upgrades required as a result of the supplemental project are considered part of that project and are the responsibility of the entity sponsoring it.

Members will be asked to endorse proposed Tariff revisions extending the deadlines for electric distribution companies (EDCs) to submit Power Meter and InSchedule data. The changes would allow load reconciliation data to be included in the calculation of balancing operation reserve deviation charges.
Members will be asked to endorse proposed Reliability Assurance Agreement revisions to allow EDCs to submit corrections to peak load contribution and network service peak load assignments until noon on the next business day. The changes, which will also be reflected in Manuals 18 and 27, are intended to aid Pennsylvania EDCs squeezed by new Pennsylvania Public Utility Commission deadlines. (See PJM MIC OKs Settlement, Credit Changes.)

3. CREDIT SUBCOMMITTEE ITEMS (1:25-1:45)

See MRC agenda item #4, above.

September 12, 2014

PJM Board Orders Filing on Capacity Parameter Changes

PJM’s Board of Managers will seek approval of changes in capacity auction parameters despite load-serving entities’ requests that it delay action pending consideration of staff’s Capacity Performance proposal.

The board ordered staff to file changes resulting from the Triennial Review of the parameters with the Federal Energy Regulatory Commission by the Oct. 1 deadline set by PJM’s Tariff.

In a letter to stakeholders late Wednesday, CEO Terry Boston said the board had endorsed staff’s proposed changes in the shape and position of the capacity demand curve, which a PJM analysis indicated could add $1.5 billion to annual capacity costs.

The board ordered staff to revise the proposal to retain the backward-looking energy and ancillary services (E&AS) offset rather than a forward-looking methodology staff had proposed. The board also decided to use the Independent Market Monitor’s proposed labor cost estimates in the calculation of the cost of new entry (CONE) instead of those recommended by PJM’s consultant, The Brattle Group.

In letters to the board last month, stakeholders representing load interests said the board shouldn’t consider the parameter changes — which failed to win stakeholder consensus Generators: Capacity Performance Unrealistic, Unfair.)

“Given the importance of the [Reliability Pricing Model] parameters in maintaining investment in infrastructure to sustain reliability over the long term, the board believes updates to these parameters are required,” Boston wrote. “The report presented by the Brattle consulting firm indicates the current variable resource requirement (VRR) curve shape does not properly reflect the varying importance of procuring capacity as the system becomes shorter or longer and that a more responsive curve shape is required.

“It is also clear that the cost of new entry values are outdated and require updates.”

E&AS

The PJM Power Providers (P3 Group), American Electric Power, Dayton Power and Light and FirstEnergy Service all urged the board to file the curve changes without delay. But they expressed concerns over staff’s proposal to switch to a forward-looking E&AS offset.

AEP, Dayton and FE said staff’s proposal lacked enough details to warrant adoption. “We would support ongoing dialogue about the merits of a forward-looking E&AS for implementation at a future date although we are not persuaded that the time is ripe for making this change,” they said.

The P3 Group said it would consider a forward-looking offset. But it said staff’s proposal “incorrectly calculates the future revenues expected by a generator and fails to recognize the necessity for making parallel reforms to use a consistent methodology for developing market seller offer caps.”

Dynegy, which urged the board to delay action on the parameter changes, also cited the “mismatch” between the forward-looking offset and the backward-looking offer cap. Dynegy also said the proposed offset could be distorted by illiquid forward markets and potential gaming of futures contracts.

Labor Costs

The board’s selection of the Monitor’s labor cost estimate ($4,179/MW-year for 2018) represents a 10% increase over the Brattle estimate ($3,788/MW-year).

In his letter, Boston acknowledged that the Triennial Review “has been a complex and, at times, contentious set of issues with strong feelings on all sides.” He said the board’s action was intended to “ensure long-term reliability at a reasonable cost.”

“We appreciate stakeholder concerns regarding the pending Capacity Performance discussion, but it is important to recognize that the installed reserve margin (IRM) calculations and the Brattle analysis already assume a higher standard of resource performance than was observed last winter,” Boston said.