Page 1603 – RTO Insider

November 4, 2014June 15, 2023

Federal Briefs

The Nuclear Regulatory Commission is increasing its oversight of Exelon Nuclear’s Calvert Cliffs Unit 2 after the company discovered that new instrumentation at the Maryland plant caused inaccurate radiation calculations that could have initiated a premature emergency declaration.

Exelon personnel in March noticed that new monitors installed five months earlier on the main steam line required recalculated thresholds for different levels of emergency. Exelon notified the NRC and fixed the problem.

“Nuclear power plant operators are always expected to err on the side of caution,” said David Lew, acting NRC Region I administrator. “But this is a case where an emergency declaration could have been made prematurely, triggering unnecessary responses.” The NRC credited Exelon with repairing the problem but criticized the company for allowing it to go unnoticed for five months.

Exelon argued that the mistake should have been classified a “green,” or very low safety, issue. The NRC determined that it was a more serious “white” issue, and it will step up oversight.

More: NRC

Wellinghoff Says Microgrids Key to Protecting System from Attacks

A system of microgrids would protect the bulk power system from calamity in the event of a physical or cyber attack, former Federal Energy Regulatory Commission Chairman Jon Wellinghoff told the GreenBiz Group’s VERGE conference last week.

“From everything I have seen, our grid is in really miserable condition from the standpoint of physical security overall,” Wellinghoff said. The answer is to diversify the system with microgrids, “so if they take down one node, it’s not going to cascade,” he said.

“Microgrids ultimately are where we need to move, to a distributed type of system, if we are ever to put out a defensible system that, in fact, can be sufficiently secure to provide us the level of reliability we all need for our businesses and homes,” Wellinghoff said.

More: GreenBiz

FERC Issues Prelim OK to Calpine-Fore River Sale

The Federal Energy Regulatory Commission gave conditional approval of Calpine’s purchase of the Fore River generating station near Boston from Exelon Generation.

The agency ruled that the sale is “consistent with the public interest,” but it set a number of conditions, such as retaining FERC’s authority over rates and other costs. The conditional approval means that the commission sees no market power issues with the sale.

Calpine announced in August that it was purchasing Exelon’s 809-MW power station in North Weymouth, Mass. The deal, expected to close by the end of the year, would make Calpine the eighth-largest generator in New England, up from 13th.

More: energybiz

Constitution Pipeline Impact Study Released by FERC, Gets OK

The Federal Energy Regulatory Commission released the final environmental impact study for the proposed Constitution Pipeline to run 124 miles from Pennsylvania’s shale-gas fields to New York. The 30-inch pipeline would have “some adverse environmental impacts,” but the impacts would be mitigated if the pipeline company sticks to its plans and FERC’s recommendations, the study said.

Final FERC approval in the form of a certificate of public convenience and necessity, and other state and local approvals, are expected next year. The pipeline is designed to carry 650 million cubic feet of gas a day to Northeastern markets. It is a joint venture among Williams Co., Cabot Oil & Gas, Piedmont Natural Gas and WGL Holdings.

More: Independent Weekender

Atlantic Coast Pipeline Files to Start FERC Approval Process

Dominion on Friday asked the Federal Energy Regulatory Commission for permission to start the pre-filing process for its 550-mile Atlantic Coast Pipeline to deliver natural gas from Appalachian shale-gas fields to North Carolina.

The four companies that want to build the $4.5 billion to $5 billion pipeline — Dominion, Duke Energy, Piedmont Natural Gas and AGL Resources — say it is needed to meet demand, especially from proposed natural gas-fired power plants. They point to a more than 450% increase in demand for gas-fired generation in North Carolina between 2008 and 2013 and a 123% increase in Virginia.

Pre-filing with FERC starts a process of government and public input, as well as initiating the numerous studies the project will need. The proposed pipeline would run from West Virginia, through Virginia and into North Carolina. Dominion said it expects to get all approvals by 2016 and complete construction in 2018.

More: _{Pittsburgh Post-Gazette}

DOE’s Rules Take Longest to Get White House Review

The White House Office of Management and Budget takes nearly seven weeks longer to review new rules from the Department of Energy than those of any other federal agency, according to a Bloomberg BNA study.

On average, the reviews by OMB’s Office of Information and Regulatory Affairs (OIRA) of Energy Department proposals take 154 days. Ahead of it is the Pension Benefit Guaranty Corp., with an average of 109 days, with the Department of Labor coming in at 107 days.

“These long delays in rules are important in terms of improving public protection,” said Ronald White, director of regulatory policy for the Center for Effective Government, a nonprofit group that was previously called OMB Watch. “It delays the benefits, and in a lot of cases we also know that OIRA reviews weaken the rules from what the agencies propose.”

The agency offered no explanation why the Energy Department rules take more time. “Our goal is to maximize the effectiveness and benefit of the rules we complete,” it told Bloomberg. “We have made it a priority to complete reviews in a timely manner.”

More: Bloomberg News

5 Companies to Get $13 Million to Develop Advanced Reactors

The Department of Energy is distributing $13 million to five companies to help them design, construct and operate advanced nuclear reactors. The awards are part of the Obama Administration’s Climate Action Plan and a DOE program started last year.

The cost-sharing grants to address technical challenges for next-generation nuclear reactors were awarded to:

REVA Federal Services, working on liquid metal-cooled reactors.
GE Hitachi Nuclear Energy, working on risk assessment practices.
General Atomics, building and testing complex silicon carbide structures.
NGNP Industry Alliance, investigating gas reactor post-accident heat removal.
Westinghouse Electric, developing thermo-acoustic sensors for sodium-cooled fast reactors.

More: Power

FERC Upholds Progress, Duke Energy Merger

Two years after the merger of Progress Energy and Duke Energy, the Federal Energy Regulatory Commission issued its final decision on the transaction. It also threw out all remaining rehearing requests.

The two companies had filed for reconsideration some of the conditions FERC set for the merger, saying they were too restrictive. The commission also denied petitions from a number of organizations — including the town of New Bern, N.C., and the Florida Municipal Power Agency — that said the commission had been too easy on Duke and Progress.

More: News & Observer

Climate Change Protestors Blockade FERC HQ, 25 Arrested

Nearly 100 climate change protestors blockaded the headquarters of the Federal Energy Regulatory Commission yesterday, snarling traffic on First St. N.E. About 25 protesters were arrested. Among those participating were marchers who arrived in Washington following a cross-country walk from Los Angeles.

The protestors cited a variety of climate-related and environmental issues, including FERC’s approval of the Cove Point LNG project in Maryland.

More: EcoWatch

November 4, 2014June 15, 2023

Company Briefs

Casino industry woes in Atlantic City are spreading to the power-generation industry.

Pepco Holdings Inc. wrote down the value of a district heating and cooling plant in the New Jersey resort from $83 million to $30 million because of “significant adverse changes in the financial condition of its customers and the business climate in Atlantic City.”

Trump Entertainment Resorts, which declared bankruptcy in September, owned two casinos served by the plant: the now-closed Trump Plaza and the Trump Taj Majal, which is expected to close in December. Pepco inherited the plant when it bought Atlantic City Electric and Delmarva Power & Light in 2002.

More: The Philadelphia Inquirer

Xcel’s Midwest Hydro Fleet Sets Sept. Production Record

Xcel Energy’s hydro fleet in Wisconsin and Minnesota set a September production record thanks to above-average rainfalls, the company said.

The company’s 19 hydro plants put out 130,537 MWh in September, eclipsing a record set in 2002 by 11,598 MWh. The company credited large amounts of rain in the Upper Midwest.

“Seven of our last nine months have been significantly above the 10-year average for hydro generation,” said Scott Crotty, manager of Xcel’s hydro operations. Hydro makes up about 8% of Xcel’s total generation. The company said more than half of the electricity it supplies customers in the Upper Midwest comes from carbon-neutral hydro, wind, nuclear or biomass sources.

More: EnergyCentral

DTE Completes $2 Billion in Upgrades at Michigan Plant

DTE Energy says its Monroe Power Plant in Michigan is now one of the cleanest coal-fired power stations in the country after it completed emission-control upgrades costing nearly $2 billion.

The upgrades at the 3,400-MW plant included new selective catalytic reduction, flue gas desulfurization equipment and construction of two 580-foot tall chimneys. The improvements will cut NOx emissions by 90%, SOx by 97% and mercury emissions by 75% to 90%.

Monroe, on the western shore of Lake Erie, was built in the 1970s. It is the largest plant in Michigan and the fifth-largest coal-fired plant in the U.S.

More: EnergyCentral

Southern’s Kemper Plant to Cost More Time and Money

Another new power plant designed to employ carbon-capture technology is racking up cost overruns.

Southern Co. says its Kemper plant in Mississippi will cost $6.1 billion, up an additional $496 million, and it is pushing back the completion date from June 2015 to March 2016. The plant’s initial cost was $2.8 billion and it was projected to begin operations in 2013.

The company said that the overruns will reduce after-tax quarterly profit by $258 million. Southern subsidiary Mississippi Power is also planning to ask the Mississippi Public Service Commission for permission to pass $167 million on to customers.

The Kemper plant is designed to convert soft lignite coal to gas that will fuel its boilers. Carbon dioxide from the combustion process is to be captured for industrial uses or storage underground.

Similar plants are also experiencing trouble. Duke Energy’s Edwardsport, Ind., plant, which uses coal gasification technology, suffered from construction delays and cost overruns. And FutureGen, a government-backed project in Illinois, was announced in 2003 and still isn’t operational.

More: PennEnergy

We Energies ‘Willing’ to Invest in New Plant to Help U.P. Shortage

Wisconsin Energy’s CEO Gale Klappa said the company is “willing to be an investor” in a new generation facility to ease an energy shortfall in Michigan’s Upper Peninsula.

The company’s Marquette plant on the Upper Peninsula is operating at a loss under orders from MISO to preserve system reliability. Wisconsin ratepayers balked at paying a premium to support the plant, and the company’s We Energies subsidiary had said it wanted to retire the plant, which would leave a generation capacity shortfall in the Upper Peninsula. The company is facing a similar situation with its Presque Isle power plant. (See related story, Michigan: FERC Rules Favor Transmission, Will Increase Costs.)

We Energies will need approval from Michigan regulators for its buyout of Integrys Energy Group, and Klappa said the company would be willing to invest in a 250- to 350-MW natural gas combined-cycle plant as part of its efforts to secure Michigan’s approval for the $5.8 billion Integrys buyout. (See related story, Integrys, Wisconsin Energy Reject Michigan Claims on Merger.)

More: Midwest Energy News

Invenergy to Build 1,300-MW Plant Near PPL’s Susquehanna-Roseland Line

Chicago-based Invenergy has filed with the Pennsylvania Department of Environmental Protection to build a 1,300-MW combined-cycle plant near Jessup, Pa.

The Lackawanna Energy Center would be the state’s second-largest natural gas-fired power plant, after PPL’s 1,722-MW Martins Creek plant in Northampton County. The plant will have three gas-fired turbines and a single steam turbine, according to company filings. Construction could begin as soon as June and be completed by 2017.

The availability of shale gas from the Marcellus field has spurred a flurry of power plant construction in Pennsylvania. Panda Power has two plants under construction and others are in the planning stages.

More: Scranton Times-Tribune

Green Mountain Gets License Extension for Vermont Hydro

The Federal Energy Regulatory Commission has granted Green Mountain Power 40-year license extensions for three hydro stations on Otter Creek in Vermont.

The licenses will allow Green Mountain to upgrade the plants from 14.4 MW to 22.8 MW. The dams are at Proctor Falls, Belden Falls and Huntington Falls. The upgrades will cost about $19 million, company officials said. Green Mountain bought the dams from Vermont Marble Power in 2010.

More: EnergyCentral

We Energies Rate Supporter Signatures May Be Fraudulent

Three organizations battling We Energies on a rate case involving solar energy have challenged the validity of petitions supporting the rate increase.

The Environmental Law & Policy Center, RENEW Wisconsin and The Alliance for Solar Choice asked the Wisconsin Public Service Commission to investigate whether 2,500 people actually signed the petitions. The organizations say many of the signatures were of those who didn’t know their names and addresses had been used and some who actually oppose the rate hike. The petition was filed by the Consumer Energy Alliance.

According to opponents, We’s proposal cuts the benefits of energy efficiency and solar energy and creates obstructions for solar suppliers other than We.

More: FierceEnergy

Pocomoke City’s Solar System Largest Municipally Owned in Md.

Pocomoke City’s 2.1-MW solar array will be the largest municipal photovoltaic system in Maryland when it goes on line in December.

“The completion of this large solar project in Pocomoke City will make the southern Eastern Shore one of the leading solar areas in the state,” said state Delegate Norman Conway, who represents Worcester and Wicomico Counties. “These solar systems are helping our regional economy by allowing our local governments, educational institutions, businesses and homeowners to generate substantial savings on their electricity bills.”

The 6,150-panel array will offset 2,067 tons of carbon dioxide annually. The system is expected to save the city more than $37,000 a year in energy costs.

More: EnergyCentral

PSE&G Starts Building Another Solar Plant on Closed Landfill

Construction has started on an 11-MW solar project atop a closed landfill, the third such energy project undertaken by Public Service Electric & Gas. When it goes on line next spring, PSE&G will have more than 31 MW of solar generation at landfills in New Jersey.

The latest project, at the closed Kinsley Landfill about 15 miles south of Philadelphia, will cover about 35 acres of the 140-acre site. Almost 37,000 panels will generate enough electricity for 2,000 average-sized homes.

The projects are part of the company’s Solar 4 All program, which installs grid-connected solar panels on landfills, utility poles, parking lots, rooftops and other sites. Plans call for developing 42 MW more of capacity in the next few years.

More: SolarServer

Delmarva Power Building 25-Mile 138-kV Transmission Line in Md.

Delmarva Power & Light is spending $29.6 million to rebuild a transmission line between the Maryland Eastern Shore towns of Denton and Millington.

Steel poles between 95-feet and 125-feet tall that can withstand hurricane-force winds will carry the line. They will replace poles and wire built in 1955. The company said work on the project will begin in February 2016 and be completed by June 2017.

More: Star-Democrat

November 4, 2014June 15, 2023

PJM DR Cos. Confident; Reject PJM EPSA Response

PHILADELPHIA — EnerNOC and Comverge executives last week expressed confidence that the demand response industry will continue to grow despite the appellate court ruling that threatens its continued participation in energy and capacity markets in PJM and other RTOs.

“It does put some constraints on us, but we are still signing up lots of customers,” Greg Poulos, manager of regulatory affairs for EnerNOC, told the PJM Market Summit conference.

Ruling in a challenge by the Electric Power Supply Association (EPSA), the D.C. Circuit Court of Appeals May 23 voided the Federal Energy Regulatory Commission’s Order 745, which set compensation rules for DR. The court said it improperly intruded on state jurisdiction.

In response, PJM on Oct. 7 proposed eliminating DR as a capacity supply resource, suggesting load-serving entities instead offer DR and energy efficiency to reduce their capacity obligations. (See EPSA Stay Complicates PJM’s 2015 Capacity Auction Plans.)

Frank Lacey, vice president of regulatory and market strategy for Comverge, said PJM’s proposal was fatally flawed, in part because it depends on LSEs.

“The LSEs, quite frankly, are EPSA,” he said, noting the group’s membership includes units of utilities such as Exelon, PPL and Public Service Enterprise Group as well as independent power producers such as Calpine and NRG Energy. “The generators don’t like demand response. They’re trying to get demand response out of the market” and boost prices.

Lacey said even well-meaning LSEs won’t be able to aggregate resources, a “core function” of curtailment service providers such as EnerNOC and Comverge.

“Close to 100% of the DR will not be available,” Lacey said. “It was not a well thought out solution.”

Howard Learner, executive director of the Chicago-based Environmental Law and Policy Center, predicted the Supreme Court will review the D.C. Circuit order and reverse it, making PJM’s “workaround” unnecessary.

“If the Supreme Court takes the case they will likely overturn. That’s how appellate litigation works,” Learner said.

November 4, 2014

FERC, New York PSC to Meet on Capacity Market Wednesday

New York and federal energy regulators will study the state’s troubled capacity market at a technical conference in Manhattan Wednesday.

It will be the first-ever joint technical conference for the New York Public Service Commission and the Federal Energy Regulatory Commission. It was scheduled after a contentious few months in which FERC approved a capacity zone north of New York City that has led to higher electric rates and a court challenge from the PSC.

The conference will be held from 9 a.m. to 4 p.m. at the New York Institute of Technology Auditorium, located at 1871 Broadway, between 61st and 62nd Streets. The conference will be webcast and transcribed.

FERC approved the capacity zone, which was proposed by NYISO, as a way to attract new generation to the area.

The conference will include sessions to discuss recent capacity market performance and ways to attract investment in resources and infrastructure. Among the speakers will be representatives from the state’s independent power producers, utilities and retailers.

“I look forward to this timely discussion of how the NYISO capacity markets work to ensure reliability and just and reasonable rates, and also to hearing about New York’s REV program,” FERC Chairman Cheryl LaFleur said. “It is critical to ensure that centralized capacity and energy markets send correct signals to support the procurement and retention of resources needed to deliver reliable energy.”

November 4, 2014

Exelon Selling Last Major Coal Generation in Fleet

By Ted Caddell

Exelon is selling its ownership interest in the Keystone and Conemaugh coal-fired power plants in Pennsylvania, leaving it with just one coal-fired plant — a 25% interest in a waste coal generator.

Exelon once had extensive coal-fired holdings but has either sold or retired them over the years as it concentrated on new gas-fired generation and its massive nuclear fleet. Now, including Keystone and Conemaugh, just 4% of Exelon’s generation portfolio is from coal.

The company announced the sale on Wednesday in a section in its earnings release, saying it would bring in approximately $475 million — $418 million after taxes — which the company will use in its acquisition of Pepco Holdings Inc.

Exelon has a 31.32% interest (535.8 MW) in the Conemaugh plant, a coal and oil plant in New Florence, Pa., northeast of Pittsburgh. It owns 41.99% (720 MW) of Keystone, a coal and oil plant in Plumcreek Township, Armstrong County – the heart of Pennsylvania’s coal country.

The other companies with ownership interests in the Keystone and Conemaugh plants are Public Service Enterprise Group, NRG Energy and PPL.

Exelon spokesman Robert Judge said the company’s shares are being sold to ArcLight Capital Partners, a private equity firm based in Boston. ArcLight has spent more than $11 billion on energy assets since 2001, including investments in wind, waste coal, coal, natural gas, oil and hydro plants, from Germany to the U.S.

Judge declined to say whether the sale signals the end to Exelon’s coal history. The sales were not mentioned during the third-quarter earnings call Thursday.

Judge said the sale is expected to close early next year. When that happens, the only coal-fired generation Exelon will own is a 25% interest in Colver, a 102-MW waste coal plant in Cambria County, Pa.

Exelon retired Unit 1 of its coal-fired Eddystone Generating Station near Philadelphia in 2011 and Unit 2 in 2012. The two units produced about 700 MW. Units 3 and 4 remain in operation and use oil or natural gas. It retired a 144-MW coal unit and a 201-MW dual-fuel unit at Cromby Generating Station near Phoenixville, Pa., in 2011.

November 4, 2014June 15, 2023

Third-Quarter Earnings Tempered by Mild Summer

By Ted Caddell

The summer wasn’t hot enough, at least for most of the PJM utilities reporting third-quarter earnings so far.

Dominion Resources blamed milder-than-normal weather for a 7% dip in earnings, while Exelon and American Electric Power reported improved results but said things could have been better with more 90-degree days. Pepco Holdings Inc. also showed improvement from a year ago, when earnings were weighed down by its retail business.

Exelon

Exelon’s net income of $993 million resulted in $1.15 per share, compared to $738 million, or 86 cents per share, for the same period last year. Its generation income jumped 57% to $771 million, including $198 million from plant divestitures – primarily the sale of its ownership in the Safe Harbor hydro plant in Pennsylvania.

Income from its distribution businesses was unimpressive. Commonwealth Edison income was unchanged at $126 million. Both PECO and Baltimore Gas and Electric showed a decline, with PECO dropping 12% to $81 million and BGE falling 8% to $46 million, all because of a milder summer. Lower summer temperatures meant less air conditioner use, so lower energy sales and distribution and transmission revenue.

Exelon CEO Chris Crane said a bright spot for the future was the PJM capacity auction, which cleared at $120/MW-day. “We think the results are encouraging for our plants that cleared, but there is an opportunity for further improvements in the market rules in the future, such as firm-fuel commitments, anti-speculation rules and, with the recent … court ruling, looking for clarity on the role of demand response [and] energy efficiency in the capacity markets.”

He noted that five of the company’s nuclear plants didn’t clear the auction, continuing a theme Exelon has been talking about recently. The company continues to seek regulatory credit for what it calls its carbon-neutral nuclear fleet. The company has said that it continues to consider retiring those plants, but Crane said no decision would be made until June 2015.

American Electric Power

AEP CEO Nicholas Akins said the company’s earnings of $1.01 a share, up from $0.89, were “respectable” given “the mild summer and our plan to accelerate spending and shift costs from future years into 2014.”

He said the company continues to invest heavily in transmission projects as well as make efforts to increase efficiencies. “We are in the middle of a multi-year plan to reposition our company focused on infrastructure investments, particularly in the transmission and regulated utility lines of our business,” Akins said.

Generation, though, will be key for AEP going forward, he said. AEP is attempting to get regulatory guarantees for its plants through power-purchase agreements, in what some analysts see as an uphill battle.

The AEP units involved “represent about one-third of the Ohio deregulated fleet,” Atkins said. “Placing these units in a PPA will preserve Ohio jobs [and the state’s] tax base, and more importantly provide a hedge to Ohio customers to mitigate price increases in the future. We estimate that this PPA arrangement will save customers approximately $224 million over the next 10 years.”

Dominion Resources

Dominion CEO Thomas Farrell II found fault with the milder summer. “Our service territory experienced one of the mildest summers in the last 30 years,” he said when announcing its 7% third-quarter earnings dip. “Excluding the 8-cents-per-share impact of the mild weather, third-quarter earnings would have been in the upper end of our range.”

The quarter saw profits of $529 million, or 90 cents a share, down from $569 million, or 98 cents a share, in the third quarter of last year.

The company said its investments in transmission, pipeline construction, solar projects and the natural gas terminal at Cove Point will be important to the company’s revenue growth. The initial public offering for Dominion Midstream Partners, which will own and operate the Cove Point project, brought in $400 million.

Pepco Holdings Inc.

Pepco, in the midst of a merger with Exelon, continued to perform on its own. CEO Joe Rigby said the company’s improved performance for the third quarter over last year was driven by higher distribution and transmission revenue.

The company closed down its retail supply business, Pepco Energy Services, last year. So the company’s balance sheet was unburdened by a business that showed a net loss of $1.31 a share during the same period last year.

Rigby noted that the proposed merger with Exelon earned approval from the Virginia State Corporation Commission, with other regulatory approvals on track for next year. He also said that Pepco will continue its ambitious reliability investment program. The company plans to spend $6.6 billion on infrastructure improvements in the next five years.

“We look forward to continued progress on our strategic goals of system reliability and customer satisfaction as we move forward with our pending merger with Exelon.”

November 4, 2014June 15, 2023

PJM MRC OKs Change on Reserves; Interchange Limit Falls Short

The Markets and Reliability Committee approved new rules allowing PJM to increase synchronized and primary reserve requirements in emergencies, an effort to reduce uplift and ensure energy prices better reflect operator actions.

A companion measure to limit interchange during emergency conditions fell just short of a two-thirds approval vote but PJM will recommend implementing the procedure anyway because it requires only manual changes, which are not subject to supermajority approval rules.

The reserve rules are a more flexible version of the short-term fix approved by stakeholders in May and incorporate a transition mechanism proposed by the PJM Industrial Customer Coalition.

Synch and Primary reserve changes (Source: PJM Interconnection, LLC) — Synchronized and Primary reserve changes (Source: PJM Interconnection, LLC)

The industrials’ proposal won 91% support in sector-weighted voting after a PJM proposal that lacked the transition fell short with only 46%.

Under the new rules, PJM can increase synchronized and primary reserve requirements under emergency conditions (Hot and Cold Weather alerts, Maximum Emergency Generation Alerts and escalating emergency conditions) when additional intraday resources are scheduled.

The volume added to reserves would be based on the quantity of additional MW committed, as opposed to the static 1,300-MW adder included in the short-term fix, which expired in September.

The transition proposal limits the impact to load pending Federal Energy Regulatory Commission approval of a new day-ahead scheduling reserve cost allocation and a second lower step on the demand curve.

PJM will implement the day-ahead unit commitment and the majority of the DASR requirement changes for winter 2015.

For the real-time changes, the proposal implements the Market Monitor’s proposal to only increase the primary reserve requirement until FERC approves the additional step on the synchronized and primary reserve demand curves. Once FERC approves the addition of the second step on the synchronized reserve and primary reserve demand curves, the PJM proposal to increase both the synchronized reserve and primary reserve requirements will become effective.

Interchange Limits

PJM’s proposal to set limits on interchange during emergency conditions won 66% support from the MRC, just short of two-thirds.

“There’s probably just one vote that needs to change” to win two-thirds support, said MRC Chairman Mike Kormos, who directed the Energy and Reserve Pricing & Interchange Volatility working group to “take one more stab” at consensus.

The working group is scheduled to meet Wednesday. PJM officials said they expect to bring the interchange volatility proposal to the November MRC meeting for reconsideration.

PJM officials said, however, that they intend to recommend operating under the new rules, which are intended to prevent markets and operations from being whipsawed by large swings in imports.

“We said we’d take unilateral action … if we couldn’t get consensus,” Kormos said.

The limit would be used when operators have made firm resource commitments and anticipated interchange schedules are sufficient to meet projected load for the hour.

Spot imports and hourly non-firm point-to-point transactions submitted after the cap is implemented would be blocked once net interchange reaches the limit. Schedules with firm or network-designated transmission service would not be curtailed.

November 4, 2014

PJM Members Approve $30K Fee on ‘Greenfield’ Tx Proposals

Transmission developers will have to include a $30,000 check with future “greenfield” proposals under a new rule approved by the Markets and Reliability Committee last week.

The fee, recommended by the Regional Planning Process Senior Task Force, is intended to cover the costs of PJM staff and external consultants performing analyses of new transmission projects under Order 1000 competitive “windows.” It will not apply to transmission owner upgrades, which PJM officials said do not require extensive analysis.

The fee was approved over opposition from Pati Esposito of Atlantic Wind Connection and Sharon Segner of LS Power, who said they favored an alternative that would require fees for transmission owner upgrades greater than $20 million in addition to a charge for greenfield proposals.

The fee received 68% support in sector-weighted voting by the MRC, enough to clear the two-thirds threshold.

PJM intends to implement the fee under a two-year test period beginning with the long-term proposal window that it will open this month.

Dan Griffiths, executive director of the Consumer Advocates of PJM States, urged members to approve the fee. “If we defer this for too long we could get flooded with proposals,” he said.

But Pat Hayes of Ameren said the fee was unlikely to discourage developers from making proposals. “It might cost three, four, five times that to come up with a proposal,” he said. “$30,000 is not going to generate the discipline you think.” Hayes said Ameren does not support imposition of any fees.

At the PJM Market Summit conference in Philadelphia earlier in the week, PJM Vice President for Federal Government Policy Craig Glazer said PJM’s resources had been strained by its first competitive window, to address stability problems at Artificial Island in New Jersey.

PJM received 26 proposals from eight developers in June 2013 and the review process has stretched on for more than a year. (See Two of 4 Artificial Island Finalists Offer Cost Caps.) “We don’t have the time or resources to do this every time,” Glazer said.

November 4, 2014

Load, Supply Trade Blame over Offer Cap Impasse

Stakeholders representing supply and load accused each other of refusing to compromise on changes to the $1,000 offer cap Thursday in one of the most acrimonious debates in the last year.

The Members Committee debate was sparked when Bob O’Connell of J.P. Morgan Ventures Energy proposed raising the cap for cost-based energy offers to $2,250/MWh from $1,000/MWh.

O’Connell, who said he was speaking on behalf of the PJM Supplier Caucus, said cost-based offers below $2,250/MWh — equivalent to a 15,000 Btu/kWh generator burning gas purchased at $150/MMBtu — should be allowed to set market-clearing prices. Cost-based offers above $2,250 would be reimbursed through uplift and not set LMPs. Price-based offers would be permitted to equal cost-based offers when the latter is more than $1,000/MWh.

The higher caps would be in effect until only June 2015, when O’Connell’s proposal would eliminate the cap altogether.

After natural gas prices spiked to more than $100/MMBtu at some pricing points in January, the Federal Energy Regulatory Commission ruled that generators could recover costs above $1,000.

PJM members agreed in April to form a task force to consider changes to the cap, but after eight meetings the group was unable to reach consensus. On Sept. 18, the Markets and Reliability Committee voted on proposals to lift the cap with none winning a two-thirds majority. (See Members Deadlock on Change to $1,000 Offer Cap.)

A proposal that would have eliminated the cap for cost-based offers and let them set LMPs was unanimously opposed by the Electric Distributor and End Use Customer sectors. An alternative that would have allowed cost-based offers above $1,000/MWh, but would not have allowed them to set LMPs, won unanimous support from the ED and EUC sectors but was opposed by most Transmission Owners and Generation Owners.

On Oct. 10, the task force met a final time, a session that PJM facilitator Adrien Ford said was marked by “long periods of silence.” The MRC voted Thursday to sunset the task force.

O’Connell said the suppliers hadn’t offered their proposal Oct. 10 because they didn’t want to negotiate in a public meeting and because the proposal “wasn’t formalized in its entirety until recently.”

Ed Tatum of Old Dominion Electric Cooperative (ODEC) said he was “disappointed” at suppliers’ characterization of load representatives as “intractable.” It was the suppliers, he contended, who had refused to negotiate.

Making a Case to the Board

O’Connell withdrew the proposal before bringing it to a vote, acknowledging that it lacked support from sectors representing load. But he said he wanted to make a case that the PJM Board of Managers — board members Sarah Rogers and Charles Robinson were in attendance — should seek FERC approval to lift the cap. Without stakeholder consensus, the only avenue for changes to the cap is a Section 206 filing by the board.

O’Connell said natural gas suppliers may refuse to provide generators with all the fuel they need to operate under PJM’s direction if they fear the cost won’t be recovered. “Keeping the cap at $1,000 is a threat to reliability,” he said. “If ever there was an issue that fell at the feet of the board this is one.”

“The principle here is very simple,” agreed Exelon’s Jason Barker. “Generators need to be guaranteed to recover costs when dispatched for reliability.”

Market Power

Load representatives said they agreed with suppliers that no generator complying with PJM dispatch instructions should be forced to do so at a loss. But they disagreed with generators over how high a new cap should be and with allowing the high offers to set clearing prices.

Susan Bruce of the PJM Industrial Customer Coalition said her group would oppose O’Connell’s proposal in part because it treated day-ahead and real-time offers the same. O’Connell said differentiating between the two offers would expose generators to potential market manipulation claims.

John Farber of the Delaware Public Service Commission said the cap functions as a “circuit breaker” to ensure ratepayers are not overcharged. Farber referenced a March report by the Independent Market Monitor, which concluded that only $9,118 of the nearly $584,000 in requested make-whole payments should be paid. (See Stakeholders Preview Offer-Cap Debate; Monitor: Generators Overstated Costs.)

O’Connell said the numbers cited by Farber do not reflect all the money at stake. He noted that Duke is seeking $9.8 million in “stranded” gas costs (EL14-45), and ODEC is seeking reimbursement of more than $15 million, including $2.7 million in excess costs incurred before FERC’s order temporarily lifted the $1,000 cap (ER14-2242). (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim.)

Counter by Load

Immediately after O’Connell withdrew the proposal, he engaged in a parliamentary skirmish with ODEC’s Steve Lieberman, who sought to describe an alternative load proposed Oct. 10. Committee Chairman Dana Horton of American Electric Power let Lieberman proceed over O’Connell’s objection.

This proposal would allow real-time cost-based offers between $1,000/MWh and $1,400/MWh to set LMP if the unit is instructed to run by PJM. Generation costs above $1,400/MWh in the real-time market would be recovered via uplift.

Dan Griffiths, executive director of the Consumer Advocates of PJM States (CAPS), said load representatives were unable to engage generators to discuss the proposal. “The other side wasn’t interested in talking,” he said.

Lieberman acknowledged his proposal also would not pass. Nevertheless, he said he wanted to present it for the board’s review.

Tatum said that O’Connell and other supplier stakeholders had refused to engage in dialogue with load representatives at the Oct. 10 meeting. “Not since high school have I had such trouble getting people to talk to me,” Tatum said.

November 4, 2014June 15, 2023

PJM Generators Seek Support for Cost of Capital Boost

PHILADELPHIA — Calpine’s Joe Kerecman rarely speaks at PJM stakeholder meetings, but he was full of questions at last week’s PJM Market Summit. One issue he raised in at least two sessions concerned the 8% after-tax weighted average cost of capital (ATWACC) the PJM Board of Managers submitted following stakeholders’ Triennial Review of capacity auction rules.

The board filed proposed revisions to the capacity market parameters in September (ER14-2940) despite a lack of consensus among stakeholders. Members voted in August on five proposals, none of which won a supermajority. (See PJM Board Orders Filing on Capacity Parameter Changes.)

The filing has prompted protests from both load, which doesn’t like the proposed changes to the demand curve, and suppliers, which oppose PJM’s labor calculations and cost of capital.

Leading the opposition on cost of capital is the PJM Power Providers (P3) group, which told the Federal Energy Regulatory Commission it should use a 10.8% ATWACC, based on an analysis by PA Consulting, rather than the 8% recommended by PJM’s consultants, The Brattle Group.

The P3 group asked FERC to order a hearing to resolve this “disputed issue of material fact.” The Electric Power Supply Association endorsed P3’s filing. Calpine is a member of both groups.

Kerecman noted that the board used a capital asset pricing model (CAPM) based on the cost of capital for NRG, Dynegy and Calpine. “But Calpine is the only company of the three that’s actually building something in PJM. So of the 10 to 12 projects that are happening [in PJM], they’re all private equity, structured finance-type projects” with higher costs of capital, he said.

Eight percent is “certainly low,” responded Jason Kahan, vice president with Energy Investors Funds of New York. “Debt right now is still cheap even if you’re doing it on an individual project. A lot of projects are getting financed at LIBOR plus 350 [basis points]. All-in debt lending rates are around 6%. But do you want take risk from an equity perspective to build a new plant at 10%? I certainly don’t. That’s a pretty thin margin with all … that you can get wrong in terms of how your plant is going to get built and how it’s going to operate.”

“I think 8% for an [independent power producer is] relatively low,” agreed Jonathon Kaufman, managing director of investment banking at Credit Suisse. “Certainly 8% for a private equity sponsor is dramatically low.”

So why, Kerecman asked, have investors and bankers been silent on this debate?

Unlike a utility rooted in a region, “we’re more opportunistic,” Kahan responded. “If we don’t like what we’re seeing in PJM, we’re going to shift our attention to other parts of the country. … We have historically stayed out of those fights. You are right.”