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.
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.”
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.
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.
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.
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.
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.”
Delaware City Refinery Drops Expansion Plan, Looking at NGLs Port Possibility
PBF Energy, owner of the Delaware City Refinery, has dropped plans for a $1 billion project to expand low-sulfur fuel production. But it is considering a $100 million investment to support cleaner fuel production and to export natural gas liquids such as propane.
PBF, in its quarterly earnings announcement, said the $1 billion hydrotreater project to produce low-sulfur fuels would have needed extensive permits. The company said it had already largely achieved production targets with improvements at its Delaware City and Paulsboro, N.J., refineries. It wrote off the value of $28 million in studies it had done to lay the groundwork for the project.
The idea of building a terminal to export NGLs at its Delaware River property, south of Wilmington, is in the early stages. There is a growing overseas demand for natural gas liquids, produced from shale-gas formations as well as refineries.
“We have a significant amount of property,” a PBF official said. “We’ve had some discussions with the state on it. I wouldn’t say they stood up and said, ‘This is the greatest idea we’ve ever heard.’” But he added that some parties are “very interested in doing it.”
Fuel cell producer Bloom Energy, a key part of Gov. Jack Markell’s economic development plan, fell short of hitting the workforce benchmarks it had agreed to under a $16.5 million state incentive grant.
Company filings from the end of September disclosed Bloom has 208 employees and an annual payroll of $9.55 million. The state grant called for 300 employees and a $12 million payroll. The company’s incentive payments are generated from a surcharge on Delmarva Power & Light bills that amount to about $5.84 a month for a typical residential customer.
Penalties won’t kick in until 2017 if the company continues to fall short, said Alan Levin, state economic development director. “While I’m disappointed they didn’t hit their number, I am not discouraged because I see them making steady progress,” he said.
Commission to Probe IPL’s Underground Network Failure
The Indiana Utility Regulatory Commission held a public meeting Monday to review reports examining the failure of Indianapolis Power and Light’s underground network in August.
IPL experienced a number of underground transformer explosions on Aug. 13, causing smoke to billow from street-level grates and forcing the evacuation of several downtown Indianapolis buildings. There were no injuries, but large parts of the downtown district went dark.
At a Monday hearing, the commission reviewed reports prepared by IPL and an independent consultant. IPL was investigated for similar blasts in 2010 and 2011.
The Board on Electric Generation and Transmission Siting is reviewing a proposal by SunCoke Energy South Shore to build a 90-MW power plant that would be fueled by gases from its proposed coke plant on the Ohio Rver near South Shore, Ky.
Coke, which is used in steelmaking, is produced by heating coal to burn off the volatile compounds. SunCoke proposes to capture the gases and use them to generate power.
Electricity would be fed to the grid through a 1-mile transmission line across the Ohio River to an American Electric Power substation in New Boston, Ohio.
Chesapeake Bay Cleanup Plan Needs to Include Conowingo
A report from the Maryland Public Policy Institute says that Maryland’s $14.4 billion plan to clean up the Chesapeake Bay to meet federal mandates ignores the effect of the single largest source of sediment flowing into the bay – Exelon’s Conowingo Dam.
The report says that most of the funds will be spent on reducing nitrogen pollution from sewage plants, septic systems and storm water outfalls, which account for only 7% of pollution. “If you decide that nitrogen is the bad guy,” and you wanted “to get rid of nitrogen in the most cost-effective way, why would you want to focus on only 7% of Maryland’s [nitrogen] source?” MPPI member James Simpson said.
The state’s plan was devised in response to a 2010 federal mandate to meet Clean Water Act standards.
U.P. Generation Shortfall, Rates Draws Crowd at Energy Summit
A looming energy crisis for the Upper Peninsula attracted an unusually large audience to Michigan’s annual Energy Summit.
More than 300 people came to Northern Michigan University in Marquette to hear about potential solutions to the crisis, which was triggered when We Energies proposed shutting down its Presque Isle plant after large industrial customers switched to different suppliers. MISO ordered the plant to stay open to protect system reliability. Michigan retail customers would foot the bill — up to $15 more a month per customer.
“I want people to understand that the problem is serious and avoidable, but in order to avoid it we need the participation of an awful lot of people … and [to] always [keep] in mind the impact on the residential ratepayers as well as the business,” said Valerie Brader, a senior policy advisor to Gov. Rick Snyder.
We Energies, based in Wisconsin, has said it would be willing to construct a new power plant if the Presque Isle plant closes. Other solutions include load control and energy efficiency.
BPU Offering Up to $3 Million for Energy Storage Projects
The Board of Public Utilities is offering $3 million in incentives to developers of energy storage systems associated with renewable-energy projects that provide on-site power to facilities.
The grants, up to $500,000 each, will spur power generators to develop energy storage capacity that builds up the state’s resiliency to blackouts. Such storage facilities are also seen as critical to resolving the issue of matching up consumer demand to the intermittent production from renewable-power generators.
The money comes out of the state Clean Energy Fund, which is financed by a surcharge on utility customers’ bills.
Piedmont Gas Granted Approval for Affiliate Agreements by State
The Utilities Commission approved agreements by Piedmont Natural Gas affiliates to sign up for a proposed natural gas pipeline that would run to the state from West Virginia. The Atlantic Coast Pipeline is a proposed 550-mile natural gas pipeline that would carry gas from the shale regions of West Virginia, Ohio and Pennsylvania.
The pipeline itself still needs regulatory approval from all the states on the route, as well as from the Federal Energy Regulatory Commission. Piedmont needed state approval because it is both a partner in the pipeline project and a proposed customer.
A pipeline carrying condensate from shale-gas wells in the state’s east to a gas processing facility in West Virginia burst and caught fire last week, burning for several hours before being brought under control.
The 8-inch pipeline carries natural gas condensate to Dominion Transmission’s Natrium Natural Gas Processing and Fractionation Facility. Condensates are valuable liquids likened to “natural gasoline” that are produced from some oil and gas wells. The accident caused no injuries or property damage, and the state Environmental Protection Agency said there was no sign of leakage into waterways.
The number of pipeline accidents has increased as the fracking boom has taken off in Ohio. There were 13 accidents last year, up from four in 2010. There have been 11 so far this year.
Future of PGW to be Addressed in Wake of Deal Collapse
The collapse of a deal to sell aging Philadelphia Gas Works to UIL Holdings has spurred the state Public Utility Commission to hold a session to address plans on what to do next with the nation’s largest municipal gas utility.
The one-day session will be on Nov. 14 at Drexel University and will focus on what to do about PGW’s high rates, crumbling infrastructure and programs for low-income customers.
The contentious $1.86 billion deal to sell PGW was engineered by Mayor Michael Nutter but scuttled by the city council last week. Nutter said the council’s killing of the deal without holding hearings or a vote was the “biggest cop-out in recent legislative history in Philadelphia.”
Corbett Vows to Protect Coal Industry if Re-Elected
Gov. Tom Corbett, trailing Democratic challenger Tom Wolf, promised voters in his state’s coal region that he will protect the coal industry if re-elected.
Corbett, in a speech in Plumcreek Township, said federal government regulation is hurting the state’s economy. “We need to get Washington and the [Environmental Protection Agency] out of our way so we can do more with the industry and continue to keep and grow our coal jobs that President Obama and his supporters are trying to kill in Pennsylvania,” he said.
Corbett also criticized his Democratic challenger for supporting a 5% severance tax on natural gas production.
“We’ve grown the natural gas industry from the fifth largest in the country to the second largest,” Corbett said. “We reduced unemployment from 8.1% to 5.7%, and we produced a balanced budget on time each of the four years I’ve been in office. When we didn’t have the money to spend, we didn’t do it. That’s what [Wolf] wants to do — tax and spend.”
Co-Op Wins Against Comcast in Pole Attachment Case
The State Corporation Commission ruled in favor of Northern Virginia Electric Cooperative, which was fighting attempts by cable giant Comcast to cut the rate it pays to use the co-op’s utility poles.
Comcast had sought to pay NOVEC according to the same formula used to compensate investor-owned utilities, but the SCC set a higher rate for the co-op. Comcast wanted to pay $7.16 a year for each NOVEC pole it used. A commission hearing examiner set the rate at $20.60. NOVEC has 52,000 poles.
“We asked to be fully compensated for providing space on our pole infrastructure to Comcast, and the rate determined by the hearing examiner, and affirmed by the commissioners, achieved most of what we were seeking,” said Stan Feuerberg, NOVEC president and CEO. Comcast said the higher cost would inhibit its ability to deliver broadband service in rural areas.
The Markets and Reliability Committee approved an initiative to ensure that generation fleet owners are properly compensated for reactive power and voltage control services as they add or retire generators.
The effort was prompted by the Federal Energy Regulatory Commission, which said there was no mechanism for obtaining refunds from fleet owners that may be collecting payments for retired plants.
“I think FERC wanted to make clear that the obligation was on the generator to” ensure it has filed updated rate schedules, MRC Chairman Mike Kormos said.
Members approved a revised problem statement including language suggested by Public Service Enterprise Group. PSEG’s Ken Carretta said the original statement assumed that fleet owners that haven’t filed revised cost schedules with FERC after plant retirements are being overpaid.
Carretta said when PSEG updated its rate schedule in 2008, its payments increased to $27 million from $9 million. “We built new units [and] made capital improvements. So it doesn’t necessarily follow that rates should go down,” he said.
PJM officials said they did not know how much ratepayers might be overpaying. “There have been a couple of occasions where this occurred,” PJM’s James Burlew said. “We know units have retired. We don’t know if these units are [still] being compensated.”
Carl Johnson, representing the PJM Public Power Coalition, wasn’t happy with PJM’s inability to answer the question. “It’s hard for me to explain to my members that we don’t know what we’re paying for,” he said.
The Markets and Reliability and Members committees approved the following Thursday with little discussion or opposition.
Markets and Reliability Committee
Manual Changes
Revisions to Manual 11: Energy & Ancillary Services Market Operations and Manual 28: Operating Agreement Accounting that will set the default Tier 1 synchronized reserves estimates to zero MW for nuclear, wind, solar, batteries and hydro generators. The change means those resources will not receive compensation unless they actually provide reserves during a spinning event.
Changes to Manual 1 to comply with a revised reliability standard given preliminary approval by the Federal Energy Regulatory Commission in September. COM-002-4 (Operating Personnel Communications Protocols) requires the use of a three-part communications process when issuing operating instructions. (See FERC Backs NERC, NAESB Standards.)
Revisions to Manual 14A: Generation and Transmission Interconnection Process that create a pre-application process for new and existing generation resource additions of 20 MW or less in compliance with FERC Order 792. Potential interconnection customers will have to submit a formal written request and a $300 processing fee. PJM is requesting these changes be effective beginning Nov. 1. (See PC Starts Work on Small Generator Interconnection Changes.)
Revisions to Manual 19: Load Forecasting and Analysis clarifying process for adjusting load forecasts due to significant load changes.
Conforming changes to Manual 18: PJM Capacity Market in response to members’ requests for details of the process for requesting and cancelling demand response maintenance outages and a FERC order allowing Annual, Extended and Limited products for DR (ER11-2288).
Transmission Owner Data Feed
Members approved Operating Agreement and manual changes to make it easier for transmission owners to access real-time generator data. The changes are intended to improve situational awareness and emergency response.
Winter Generator Testing
Members approved rules for voluntary winter testing of seldom-used generators. The tests would be limited to generators that haven’t run in the prior eight weeks and days when temperatures are below 35 degrees Fahrenheit. (See Winter Testing Could Cost $15.9M.)
IRM Set at 15.7% for 2018/19
Members approved a recommendation to leave PJM’s Installed Reserve Margin at 15.7% for planning year 2018/19, unchanged from 2017/18.
Manual 29 Revisions – Billing Adjustments
The committee approved a problem statement and issue charge on first read regarding revisions to Manual 29: Billing. The changes are intended to prevent cost shifting when miscellaneous items or special adjustments are underpaid.
Members Committee
Manual, Operating Agreement Changes
The MC endorsed revisions to Manual 11: Energy & Ancillary Services Market Operations and Manual 15: Cost Development Guidelines 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.
Members revised the conflict of interest policy in the Operating Agreement to reflect the increasing number of consumer product companies, manufacturers and technology companies becoming involved in the electric industry. (See PJM Revising Policy on Prohibited Investments.)
Nominating Committee Elected
The MC elected the following to one-year terms as members of the Nominating Committee, which recommends candidates for the Board of Managers:
Electric Distributors: Steve Lieberman, ODEC
End Use Customers: Jackie Roberts, West Virginia Consumer Advocate Division
Generation Owners: Ken Foladare, IMG Midstream
Other Suppliers: Pati Esposito, American Wind Connection
Transmission Owners: Hertzel Shamash, Dayton Power and Light
Presque Isle power plant (Source: Wisconsin Energy)
Michigan officials and members of the state’s congressional delegation urged the Federal Energy Regulatory Commission last week to rethink its approach to replacing the retiring Presque Isle power plant, saying FERC is favoring expensive transmission over cheaper generation.
The officials are seeking new generation to replace Wisconsin Energy’s 430-MW coal-fired plant in Marquette, Mich., rather than a transmission expansion that could cost $600 million or more.
Invenergy Thermal Development is in discussions with Cliffs Natural Resources to build a combined heat and power cogeneration facility that would serve Cliffs’ mining complex in Marquette County and “substantially replace” Presque Isle’s output, Gov. Rick Snyder, Attorney General Bill Schuette and U.S. Reps. Fred Upton and Dan Benishek wrote in a six-page letter to FERC commissioners.
But the officials complained that a transmission alternative is being given a “procedural advantage” because of “jurisdictional lines that prevent holistic consideration of alternatives.”
“Under the federal rubric that has been set up, transmission solutions are the only solutions that MISO can require be funded, and generation solutions can only be considered once they are essentially guaranteed to come into service,” they wrote. “In short, the current structure’s only tool is a hammer, and it is trying to fix every situation with a nail. We believe that sometimes transmission is the appropriate investment. But sometimes it is not, and we need entities that have a full toolbox — both information and regulatory authority — ready to engage in the determination of what solution is the right one.”
The officials also complained that FERC “is repeatedly being asked to assume more of the responsibilities that have been carried out well by state commissioners for years.”
Failed Deal
Wisconsin Energy’s We Energies decided to retire Presque Isle rather than invest in environmental upgrades to keep the plant running.
Last November, Michigan utility Wolverine Power Cooperative struck a deal with We Energies in which Wolverine would spend $135 million on environmental upgrades in return for a one-third ownership stake in the plant.
Michigan officials said that the deal was attractive because it maintained reliability, provided for environmental improvement and would have been “vastly more affordable for ratepayers than any other solution.”
The deal fell apart after Cliffs Natural Resources agreed to buy power from Integrys Energy Services, a subsidiary of Integrys Energy, instead of We Energies. With no other offers available, We Energies decided it would close Presque Isle.
Wisconsin Energy’s proposed merger with Integrys requires the latter to divest its Energy Services unit.
After the merger, the Michigan leaders noted, Wisconsin Energy would own more than 60% of transmission operator American Transmission Co., “which would own and operate any transmission needed to offset [Presque Isle’s] retirement.”
“The new proposed combined company also stands to benefit significantly from the increased transmission that would be needed to be constructed as a result of the [Presque Isle] retirement without generation replacement.”
The Michigan leaders told the commission it should consider whether new transmission, new generation or a combination of both is the best solution for replacing Presque Isle.
“That is unfortunately not the course of action being pursued in the many dockets now before you, nor is it much evidenced in the decisions made to date by FERC, MISO and other federally regulated entities regarding this problem.
“Unfortunately, to date, it appears that all these entities’ processes are designed to favor one possible solution – running [Presque Isle] until a great deal of transmission can be built, and all at ratepayer expense.”
