WASHINGTON — FERC Commissioner Philip Moeller announced last week he will leave the commission at the end of the month although President Obama has yet to appoint his successor.
Moeller
Moeller, one of two Republicans on the five-member panel, announced in May that he would not be returning when his term expired June 30. He said that he expected to serve until his replacement was confirmed.
Nearly five months later, however, Obama has yet to name a replacement. Moeller’s extended term would end when the current session of Congress adjourns this fall.
Even if Obama were to nominate a replacement immediately, it could be months before the commission returns to full strength. Even non-controversial FERC appointees can get enmeshed in Congressional horse trading. For controversial appointees, the process can be even more tortuous.
The seat of former Chairman Jon Wellinghoff went unfilled for almost eight months after his resignation in November 2013. After Obama’s first nominee, Ron Binz, withdrew under fire from the coal industry, it was another five months before Obama named former FERC enforcement chief Norman Bay in February 2014. It took Bay five months to win confirmation on a party-line vote in July 2014.
FERC’s newest member, former Arkansas regulator Colette Honorable, was confirmed unanimously to replace Democrat John Norris after a four-month gap last year.
When Moeller announced his departure in May, speculation on his successor centered on Patrick McCormick III, chief counsel for Senate Energy and Natural Resources Committee Chairman Lisa Murkowski (R-Alaska). (See Moeller Leaving FERC.)
McCormick’s appointment could have challenged the traditional comity at FERC, given Murkowski’s opposition to Bay’s nomination.
But in light of the lengthy delay since his name was circulated, McCormick may no longer be in contention. Asked by Politico whether McCormick was under consideration, Murkowski said, “He’s a very happy man at the Senate Energy Committee. I’m sure happy having him there.”
Moeller, who was appointed by President George W. Bush in 2006, said he plans to seek employment in the energy industry.
Before joining the commission, he worked from 1997 through 2000 as an energy policy adviser to U.S. Sen. Slade Gorton (R-Wash.). Before joining Gorton’s staff, he was the staff coordinator for the Washington State Senate Committee on Energy, Utilities and Telecommunications. He also headed the D.C. office of Alliant Energy and worked in the D.C. office of Calpine.
PJM and MISO will make a joint filing with FERC later this year to eliminate the $20 million minimum for interregional market efficiency projects, PJM officials told the Transmission Expansion Advisory Committee last week.
The two RTOs indicated their willingness to do so in response to a complaint by Northern Indiana Public Service Co. (EL13-88). NIPSCO, which filed the complaint in 2013 over its frustrations with MISO and PJM’s interregional planning process, says nothing much has changed since then. (See MISO-PJM Cross-Border Projects Still Languishing, NIPSCO Says.)
In an Aug. 14 filing, PJM and MISO said they would lower or eliminate the $20 million threshold. MISO also said it would inform FERC by the second quarter of 2016 on whether it will eliminate its 345-kV minimum on such projects.
PJM and MISO embarked this year on a search for “quick hit” transmission projects on which they might collaborate to relieve congestion.
In a Sept. 3 filing, PJM said the studies found that about three-quarters of the $400 million in cross-border congestion identified was expected to be relieved by regional transmission projects under the MISO and PJM tariffs and that congestion on lower voltage facilities could be eliminated by upgrades costing less than $5 million.
“Reduction or elimination of the $20 million threshold in the [joint operating agreement] and the [345-kV] voltage threshold in MISO’s regional process would enable quick-hit projects to qualify as an interregional project,” PJM said.
PJM officials said they and MISO officials will make a joint filing to remove the $20 million threshold from their Joint Operating Agreement. MISO would file alone if it decides to eliminate the 345-kV threshold from its Tariff.
AEP to Build Rockport Line as Supplemental Project
American Electric Power will build a 14-mile double-circuit line between its Rockport substation and MISO’s Duff-Coleman 345-kV line as a supplemental project in the PJM Regional Transmission Expansion Plan. The project, which is intended to solve stability problems at the substation, will piggyback on MISO’s planned Duff-Rockport-Coleman project. (See MISO Staff Recommends 3 Economic Projects.)
Cost sharing for Duff-Rockport-Coleman (Source: MISO)
“We clearly should have gotten involved [in the project planning] much earlier,” said Steve Herling, vice president of planning. “MISO was great,” he added, noting that MISO delayed its process to allow PJM to conduct its own analyses.
“We’ve already had a number of conversations with MISO as to how we can be better synched up in the future,” Herling said. “We’re pretty happy it didn’t fall through the cracks. Next time we want to do it in a more formalized way.” (See related story, FERC Sets Nov. 12 Tech Conference on PJM Tx Planning Rules.)
Most AP South/AEP-DOM Proposals Clear Sensitivity Tests
All but one of 11 proposals that passed the initial benefit-cost ratio to address congestion in the AP South/AEP-DOM area also show positive benefits under 10 different sensitivity analyses, PJM planners told the TEAC.
The sensitivities included fuel prices (+/- $1/MMBtu), load forecasts (+/- 2%), interface ratings (changes in anticipated project impacts by 20%) and combinations of fuel price and load forecast sensitivities.
All but two of the projects cleared the 1.25 B-C ratio under all sensitivities and all but one showed congestion savings for the entire RTO. However, nine of the 11 worsened congestion on AEP-DOM alone (see chart).
Planners will continue their analysis by combining components of multiple projects as well as considering projects involving capacitors and reactive devices.
Planners evaluated six planned market efficiency projects but determined that none of them should be accelerated because the projects are either too large to reschedule or their in-service dates are in the near future. An additional six projects expected to reduce congestion also were ineligible because they are being developed by MISO.
SVCs Recommended to Fix High Voltage in AEP, PSEG
Planners will recommend more than $51 million in upgrades to address high voltages in the AEP and PSEG transmission zones.
The AEP project would involve installation of a 450-MVAR static VAR compensator (SVC) at the Jacksons Ferry 765-kV substation and a 300-MVAR shunt line reactor on the Broadford end of the Broadford-Jacksons Ferry 765-kV line. It is expected to be in service in June 2018 at a cost of $51 million.
Planners also will recommend six shunt reactors on the PSEG system in addition to about 1,500 MVARs of approved reactors and SVCs planned to go in service by 2016. Three devices are required as soon as possible; the other three will be installed in coordination with the Bergen-Linden Corridor 345-kV project. No cost estimate was listed for these projects.
Planners Choose $25.8M AEP Proposal over Cheaper LS Power Option
PJM will recommend AEP’s proposed $25.8 million upgrade rather than a $7.4 million proposal by LS Power to address low voltage and overload problems in the AEP zone.
Paul McGlynn, general manager of system planning, said PJM determined that LS Power’s proposal to build a new Grassy Creek switching station would be insufficient to address expected load growth driven by shale gas production in the area. The AEP project, due in service by June 2020, is expected to prevent violations for at least 15 years, PJM said.
“We believe [the AEP project] is the better, more robust solution,” he said.
LS Power’s Sharon Segner questioned why AEP’s more expensive project was selected, saying PJM’s load growth assumptions are too high. “We want to make sure the right solution is picked, even if at the end of it, AEP takes the idea that we proposed,” she said.
Dominion to Spend $273M+ on End-of-Life Projects
Dominion Virginia Power will spend more than $273 million on nine projects to replace aging transmission lines in accordance with its “end of life” criteria, which sets the lifespans for wooden structures, conductors, connectors and porcelain insulators.
The rebuild of the Cunningham-Dooms 500-kV line is expected to cost more than $100 million, with an in-service date of June 2020. Eight other projects, expected to be completed between 2016 and 2019, will total about $173 million.
Exelon Retiring Perryman Unit in BGE
Exelon has decided to retire, rather than repair, its damaged 51-MW Perryman 2 generator in the BGE zone.
Exelon told FERC in April that the 43-year-old oil-fired unit experienced a “severe mechanical failure” in February that would take nine months to repair (ER15-1611).
Exelon said that a portion of a compressor shroud detached, damaging a number of the compressor’s components. “In addition to the compressor issue, electrical testing revealed that the unit’s generator field and stator windings are in a degraded condition,” Exelon said.
PJM planners are conducting a reliability analysis on the retirement request, which was filed Oct. 2. Exelon requested the retirement be effective Jan. 1.
In May, the D.C. Council unanimously approved $250,000 for the Office of the People’s Counsel to conduct a study on the feasibility of the district replacing Potomac Electric Power Co. with a city-owned utility.
The vote set lobbyists for Pepco — no strangers to the Wilson Building, D.C.’s city hall — into high alert.
Public records show that in June alone, Pepco and Exelon lobbyists Tina Ang and John Ray, of law firm Manatt, Phelps & Phillips, communicated more than 60 times with seven D.C. councilmembers or their aides, including in-person meetings, phone calls and electronic messages.
By the end of the month, the study — included in the city’s fiscal year 2016 budget — was dead, with the council voting 7-6 to reallocate the funds for a study on “emerging alternatives” for energy and energy efficiency.
“Presumably, they didn’t even want a study,” said Councilwoman Mary Cheh, an opponent of Exelon’s bid to acquire Pepco who had pushed for the original study.
The amendment to reallocate the funds was sponsored by Councilmember Anita Bonds. Bonds or her staff communicated on 19 occasions with the utility lobbyists in June. Councilmembers Jack Evans, Brandon Todd, LaRuby May and Vincent Orange — all of whom met personally with the lobbyists — and Yvette Alexander, who sent a staff member to the meetings, also voted for the change.
The vote was but one signal of Pepco’s clout in the district.
Orange, a former regional vice president for PHI, chairs the Council’s Committee Business, Consumer and Regulatory Affairs.
Council Chairman Phil Mendelson has been criticized for voting on Pepco matters because he holds enough stock to be required to financially disclose it.
Attorney General Karl Racine, who helped negotiate the Oct. 6 settlement between Exelon and Mayor Muriel Bowser, and Racine deputy Natalie Ludaway conducted work on Pepco’s behalf while at their former law firms. Beverly Perry, senior adviser to Bowser, retired in 2013 as senior vice president and special adviser to the chairman of PHI.
Charity Returned?
In their bid to win approval of the merger, Pepco officials also have looked to cash in chits with the dozens of community organizations the company supports with charitable contributions. In the district alone, Pepco spends about $1.6 million annually on charitable contributions.
Exelon and Pepco claim that more than 80 D.C.-area organizations support the merger, including 30 businesses and associations and nearly four dozen non-profit organizations. At least half of the non-profit groups listed in support were recipients of contributions from Pepco in 2014 or receive funding from the United Way of the National Capital Area, where Pepco CEO Joseph Rigby is the immediate past chairman. John Huffman, CEO of Pepco Energy Services, serves on the board of the Capital Area Food Bank, one of the charitable groups backing the deal.
Business Community Lines up in Support
Rigby also serves on the senior council of the Greater Washington Board of Trade, as well as the boards of the Federal City Council and the Economic Club of Washington — all of which have endorsed the merger.
James C. Dinegar, president of the Board of Trade, told The Washington Post that rejection of the deal would hurt the region’s economy. “There’s a big concern that we’re hanging out the ‘Closed for Business’ sign in the District of Columbia,” he said.
The powerhouse at Duke Energy’s retired Cliffside Steam Station in Mooresboro, N.C., came down in a cloud of dust last week, the latest demolition Duke has conducted to modernize its generation fleet.
The coal-fired station went into service in 1940, and units 1 through 4 were retired in 2011. Units 5 and 6 are coal-fired units equipped with modern scrubber technology and still operate as part of the James E. Rogers Energy Complex.
Entergy Executive Vice President and Chief Operating Officer Mark Savoff and Executive Vice President and Chief Nuclear Officer Jeff Forbes announced coordinated retirement dates last week.
Both executives plan to shift to advisory roles on Nov. 1 before retiring in 2016’s first quarter. At that time, Tim Mitchell, Entergy’s senior vice president of nuclear operations, will be named acting chief nuclear officer. In an executive restructure, the chief nuclear officer will directly report to Entergy Chairman and CEO Leo Denault. Mitchell will also be a candidate in Entergy’s search for a permanent chief nuclear officer.
Savoff and Forbes joined Entergy in 2003 and oversaw the transition of Entergy’s transmission system to MISO in 2013.
DTE Energy is teaming up with GE Hitachi to design a new type of boiling water reactor. While others are working on smaller, modular designs, the two companies are working on advancing the first-ever Economic Simplified Boiling Water Reactor (ESBWR).
The ESBWR incorporates passive safety systems, including a reactor that can cool itself for more than seven days without backup power or any human input. DTE has already received licensing from the Nuclear Regulatory Commission for the ESBWR.
The company said it has no current plans to start construction but said it is “keeping the option open, given the long-term environmental and economic advantages of nuclear power.” Dominion Virginia Power has selected the new design for a possible third reactor at its North Anna site in Virginia.
Alliant Energy subsidiary Interstate Power & Light in Iowa is planning to increase its total solar energy capacity by 50%, according to a recent request for proposals.
The company said it is looking to develop solar projects of between 1 and 10 MW. It currently purchases about 22 MW of solar capacity from about 1,650 customers in its service territory.
Alliant said the plan is unrelated to an Environmental Protection Agency air emissions settlement that calls for it to spend $6 million on environmental mitigation projects, which could include solar generation.
Xcel Energy to Accelerate Minnesota Wind, Solar Investments
Xcel Energy says it will reduce its greenhouse gas emissions in Minnesota by increasing wind and solar power investment and replacing two coal-burning generators with a natural gas-fired unit in the mid-2020s.
The plan, submitted to state regulators, would reduce carbon dioxide emissions in the Upper Midwest 60% by 2030 compared with 2005 levels. Until now, Xcel had aimed for a 40% reduction over that period.
Two of the three coal-fired units at Xcel’s Sherco power plant — Xcel’s largest in the region — would be retired in 2023 and 2026 under the plan. The two units, built in the 1970s, would be replaced by a new power plant fueled by natural gas.
PSEG Combined-Cycle Project to Deliver Power by Summer 2018
Construction on PSEG Power’s 540-MW Sewaren 7 combined-cycle project is expected to begin next year at an existing power station site in Woodbridge, N.J.
The $600 million dual-fuel gas-turbine facility is set to deliver power to the PJM market for the summer of 2018.
The project was finalized after clearing the Base Residual Auction in August.
Residents in Onalaska, Wis., are concerned over Dairyland Power Cooperative’s planned replacement of a 65-year-old 161-kV line.
Dairyland, which is based in La Crosse, has been working nearly a decade to replace the 9-mile stretch of line connecting power plants in Alma and Genoa to the grid, and designs are not yet ready, in spite of a late 2016 start date. The cost of the project is calculated between $7 million and $8 million. Other transmission lines in the area have been rebuilt recently or are in the process of replacement.
Residents are worried that the new line, which will carry twice the electricity at the same voltage, will increase exposure to electromagnetic radiation. Dairyland says raising the wires will mitigate exposure.
NuScale Seeking British Partners for Modular Reactor Design
NuScale Power, a U.S. company developing a small modular reactor with the help of a $217 million Department of Energy grant, is looking for a partner to help make the design a reality in the United Kingdom.
The company, mostly owned by Fluor Corp., is distributing a prospectus in the U.K. seeking a partner in what it says is a chance to get a piece of the $612 billion nuclear market by 2035.
NuScale’s design is on track to come up for U.S. certification next year, and the company says it expects to receive U.S. regulatory approval in the early 2020s. It is currently developing a test model in Idaho, using technology that can be customized for scale, allowing deployment in series, with up to 12 small reactors totaling about 600 MW.
Northern Indiana natural gas and electric provider NIPSCO has asked state regulators for an 11.5% hike in residential electric rates. Indiana’s industrial utility customers are protesting the request.
Joseph Hamrock, CEO of NiSource, parent company for NIPSCO and utilities in six other states, said the increases are needed to fund plants, poles and wires that serve as fail-safes even in light of new generating technologies.
South Field Energy to Build 1,100-MW Nat Gas Plant in Ohio
South Field Energy announced plans to build a $1.1 billion, 1,100-MW natural gas-fired power plant in Columbiana County, Ohio.
South Field and other companies are taking advantage of the cheap gas being produced at Utica Shale fields in the state. It is the sixth natural gas plant under construction in Ohio, according to the Akron Beacon Journal.
Construction would start in 2017, and the plant should be operational by 2019. South Field is also building an $899 million gas-fired plant in Carroll County.
Ameren increased its quarterly dividend on common stock, from 41 cents/share of common stock to 42.5 cents, an increase of 3.7%. The common share dividend is payable Dec. 31 to shareholders of record at the close of business on Dec. 9. The company’s board of directors also declared quarterly cash dividends to all classes of Ameren Missouri stock and all classes of Ameren Illinois preferred stock.
A study released last week by the American Public Power Association estimates that PJM’s Capacity Performance rules will increase costs to consumers by $7.3 billion over the 2016-2019 delivery years — a tally in line with PJM’s own estimates.
But while PJM says the increased capacity costs will pay off in improved reliability and reduced energy market prices, APPA says the spending is not justified.
“PJM’s recent changes are an over-reaction to the ‘polar vortex’ and address a problem that was largely already addressed by PJM and market participants through various other measures,” said Joe Nipper, APPA’s senior vice president of regulatory affairs and communications. “As a result, bill-paying consumers will pay a lot more for the same product.”
The report was prepared by James Wilson, who also consults for state consumer advocates in PJM. Wilson said that the transition auctions recently held for the 2016/17 and 2017/18 delivery years resulted in $4 billion in additional costs to upgrade 60% and 70% of “base” capacity to Capacity Performance, respectively.
In addition Wilson estimates that the Base Residual Auction for 2018/19, which cleared at $164.77/MW-day, would have cleared at $124.23/MW-day if not for the requirement that 80% of the resources acquired be CP. That, Wilson said, increased the total BRA cost to $10.9 billion, an increase of $3.3 billion. Wilson’s quantitative findings are in line with PJM’s own calculations.
PJM said the incremental cost of the 2016/17 transition auction was $2.3 billion, slightly below the estimate of $2.5 billion to $3.6 billion PJM and the Independent Market Monitor had predicted in a joint analysis. The increase for 2017/18 was $1.7 billion, PJM said (versus an estimate of $3.1 billion to $4.2 billion).
The RTO said the 2018/19 BRA represented a $3.4 billion increase over the previous year’s auction, an amount that is within the $2 billion to $5 billion range PJM and the Monitor had expected. (See PJM Transition Auction Means Reprieve for Exelon Nukes.)
Different Conclusions
But while Wilson’s math generally agrees with PJM’s, he does not agree with the RTO over what ratepayers are getting for their money.
“Improved generator performance certainly would have resulted in much lower energy costs during the ‘polar vortex’ period of extreme cold in early 2014, when very high forced outage rates caused price spikes in the PJM energy markets,” Wilson wrote. “However, that very extreme period followed 19 winters during which such extreme cold did not occur, capacity was never scarce during winter and winter energy prices remained low in PJM.
“The polar vortex period revealed accumulated fuel and winterization issues at many plants. Apparently, many of these issues were resolved by the winter of 2015, when performance was much improved. The improved performance in winter 2015 reflects numerous steps taken by market participants and PJM following the polar vortex events, and well before Capacity Performance was approved or implemented.
“So it is unclear that CP is likely to have a substantial incremental impact on future energy prices. The expected value of the incremental impact of CP on future annual energy prices is likely an order of magnitude lower than the estimated impact on capacity cost developed in this report.”
“The combination of the changes to the [variable resource requirement] curve and the CP rule changes caused capacity prices in the 2018/2019 BRA to be higher than they otherwise would have been,” PJM said in a statement. “However, PJM is confident that the implementation of Capacity Performance has been the right approach to making the grid more reliable and benefiting consumers, and that consumers will, in fact, enjoy substantial benefits in the form of lower energy prices should extreme weather conditions materialize again as they have in the recent past. The results of the annual and transitional auctions demonstrate the market was ready and prices were competitive.”
The Massachusetts Department of Public Utilities has ruled that electric distribution companies can sign contracts for natural gas capacity and pass the costs on to electric ratepayers (15-37).
Proponents of building gas infrastructure to supply electric generation have argued that the increasing reliance on natural gas requires additional pipelines to increase supply and lower high prices in the winter. After an investigation and proceeding, the DPU on Oct. 2 said the Electric Restructuring Act of 1997 did not preclude it from approving such contracts.
“The department finds that an EDC contract for pipeline capacity would be consistent with the Restructuring Act if an EDC is able to demonstrate that entering into a contract would result in cost savings for EDC ratepayers and otherwise satisfies the standard of review for approving EDC gas capacity contracts,” the order states.
The DPU’s order was in response to the state Department of Energy Resources’ April 2 petition requesting an investigation into ways new natural gas capacity could be added. The department sought to determine if there was an “innovative mechanism” for EDCs to add new natural gas capacity into the region to benefit electric ratepayers, and if cost recovery was appropriate.
“An EDC must demonstrate that the proposed contract (1) results in net benefits for the Massachusetts EDCs’ customers at a reasonable cost, and (2) compares favorably to the range of alternative options reasonably available to the EDC at the time of acquisition of the resource or contract negotiation,” the DPU order said.
Kinder Morgan subsidiary Tennessee Gas Pipeline, which is developing the proposed Northeast Energy Direct pipeline, said the order “is an important step in ensuring that electric generators have reliable access to the fuel needed to generate electricity within the ISO-NE transmission grid.” The project is among those that could be funded under the order. (See NH PUC Staff: Northeast Energy Direct Pipeline Would Lower Power Prices.)
A critic of the move, Massachusetts Attorney General Maura Healey, had argued during the proceeding that the restructuring law limited the regulators’ ability to act and questioned their assumptions. “Because of legal concerns with the DPU’s proposal and the risk to ratepayers, throughout this proceeding, our office urged the department to fully and carefully analyze the need for additional gas capacity before moving forward with any proposal that requires customers to bear the risk of a large infrastructure project,” said Chloe Gotsis, spokeswoman for the attorney general.
This is not the last word from Healey’s office. In July she commissioned a study to address the need for additional gas capacity in New England region. The study is expected by the end of the month.
The company producing the study, Boston-based The Analysis Group, has already looked askance at another Massachusetts energy proposal that it says saddles ratepayers with excessive costs. It recently conducted a study for the New England Power Generators Association critical of imported Canadian hydropower. (See New England Generators: State Interventions Risk Market Development.)
D.C. Mayor Muriel Bowser and Exelon CEO Chris Crane announced Tuesday that Exelon would invest $78 million in the district and protect consumers from rate hikes for three years under a settlement they hope will persuade the Public Service Commission to approve the company’s $6.8 billion acquisition of Pepco Holdings Inc.
Bowser
“I believe this proposal is good for our economy and environment, and I’m asking the PSC to support the merger,” Bowser said in an afternoon press conference that also featured two former critics of the merger: People’s Counsel Sandra Mattavous-Frye and Attorney General Karl Racine.
“My sole objective has been to assure all consumers receive tangible and measureable benefits. … The applicants came back and took us seriously — they made major concessions,” Mattavous-Frye said. “The bottom line is: This is a good deal.”
Racine, who had filed a 40-point critique of the merger with the PSC and went on to be part of the negotiating team, also gave his support.
“We believe we’ve got a good deal that does look out for the ratepayers on Day 1,” Racine said. “I’m satisfied that we’ve pushed Pepco-Exelon to do the right thing.”
Bowser said the joint applicants are awaiting guidance from the PSC on what form the filing should take — a new application or an amendment to the existing case.
One of the main concerns dogging the deal has been a perceived conflict of interest between Exelon’s commitment to its nuclear fleet and pursuing the district’s goal of renewable energy.
Mattavous-Frye said the concern would be addressed with “checks and balances” included in the settlement.
“We have provisions that require the company to implement specific environmental and sustainability policies,” she said, including the strengthening of “ring-fencing” protections separating PHI’s finances from that of Exelon’s nuclear fleet and its other affiliates.
Anya Schoolman, president of solar power advocate group DC SUN, said the settlement “does nothing to change the fundamental conflict of interest identified by the Public Service Commission.”
“Allowing Exelon to take over Pepco will take money out of the pockets of D.C. ratepayers while providing them no tangible benefit,” Schoolman said. “It will also harm the ability of D.C. residents to develop their own clean, cost-effective energy. The token renewable energy provisions in the Exelon settlement are a smokescreen that will allow the company to dismantle the progress the district has made to develop renewable energy.”
The $78 million investment is five times more than Exelon’s initial pledge of $14 million and would go toward promoting sustainability, increasing reliability and supporting low-income residents, Bowser said.
Of that, $17 million would be put toward conserving natural resources and the environment and promoting energy efficiency. The merger, she said, will improve reliability, in part by allowing microgrids to connect to the grid.
Exelon also would set aside $25 million to offset rate increases through March 2019, and within 60 days of the merger it would disburse $14 million to customers — a one-time credit of about $50.
Exelon and PHI have committed to moving 100 jobs to the district from elsewhere and hiring at least 102 union employees within two years, meanwhile dedicating $5.2 million in workforce training for district residents, Bowser said.
“I believe this settlement is in the best interest of the district now and in our future,” said the mayor, saying that it reflects the “fresh approach to energy” she has brought to the district.
Said Mattavous-Frye: “My goal has been to ensure all customers, but particularly residential customers, got the best deal possible. … I could not, without abrogating my statutory responsibility, not take into account how consumers would benefit. I will do everything in my ability to make sure these commitments are followed through.”
Exelon’s Crane also spoke briefly. “We really do appreciate the responsibility of serving the nation’s capital,” Crane said, adding, “The last 30 days has been very beneficial for us.
Crane
“Our enhanced local presence will continue to drive our focus on what the needs are in the community.”
The merger already has been approved by FERC and regulators in Delaware, New Jersey, Maryland and Virginia. The state deals contain a “most favored nation” status, which means the companies may have to revisit those agreements to achieve parity with the concessions being offered the district.
“We will have to sit down and determine what effect this will have on Delaware’s settlement,” said Dallas Winslow, chair of the Delaware Public Service Commission. Winslow said he could not comment further because the issue will come before him and the commission.
Pepco shares rose Tuesday afternoon as word of the settlement circulated, with shares rising as high as $26.49 in after-hours trading, up more than $1 on the day. Exelon shares, which also rose earlier in the afternoon, fell after the details became clear, closing down 9 cents to $30.21 and falling further after hours.
Last week, Exelon asked the agency to reconsider its decision, taking issue in a 43-page filing with the PSC’s findings that the deal would not be in the public interest and it would not be in the public interest to identify additional conditions that could make it so. The filing came at the same time the mayor confirmed her office was discussing a settlement. (See Exelon Appeals DC PSC Decision; DC Mayor Confirms Negotiations.)
LITTLE ROCK, Ark. — MISO said last week it may increase its energy market offer cap to $1,500/MWh this winter in response to expected FERC action.
Staff told the Market Subcommittee last week it is considering three interim energy offer cap options: 1) no change from current practices; 2) last winter’s revenue sufficiency guarantee (RSG) approach, which offered compensation through uplift; and 3) increasing the energy cap above the current $1,000/MWh.
Because MISO has increased its reliance on gas-fired generation, a repeat of the gas price spikes seen during the 2014 polar vortex could result in hundreds to thousands of megawatts of capacity exceeding the current cap, Markets System Analyst Chuck Hansen told the group.
MISO’s market engineering team has already tested systems for energy offers up to $3,000/MWh and found no issues that would prevent a higher cap. The team also simulated higher gas prices by increasing offer curves for gas plants and found that market signals became distorted as the price signals reached the cap, Hansen said.
Hansen said increasing the energy offer cap to $1,500/MWh would accommodate gas prices reaching $100/MMBtu, but studies show offers above that would increase the likelihood of the system marginal price being greater than the value of the lost load when operating reserves are scarce.
“Anything we do should not be considered permanent, given FERC’s pending action,” said Jeff Bladen, MISO’s executive director of market design.
FERC on Sept. 17 announced its intention to take action on offer caps and other price formation issues, though it offered no timeline. The statement came in a Notice of Proposed Rulemaking (RM15-24) that would require organized markets to settle real-time energy and operating reserve transactions financially at the same five-minute time interval that it dispatches those resources. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)
MISO Market Monitor David Patton has been recommending five-minute settlements since his 2012 State of the Markets Report.
“Any time you’re selling a product,” Patton told the MSC, “I believe you should be paid for the value of the product in the time period it is being delivered.”
Some stakeholders expressed support for the 2014-15 winter solution and apprehension for raising the energy cap.
“We really want your feedback,” Bladen said, urging input on fixed-offer caps and whether generators should be able to recover verifiable fuel costs beyond the cap using uplift, as was the case last winter.
Based on the feedback (due Oct. 6), MISO will present and discuss its proposal at the Oct. 27 MSC meeting. It has targeted Nov. 1 for a FERC filing, with a Jan. 1 implementation date.
Hansen said FERC’s guidance will be incorporated into a permanent offer cap solution. He said MISO will continue to monitor neighboring RTO actions on offer caps and coordinate as appropriate.
On Thursday, two days after the MSC meeting, PJM stakeholders overwhelmingly approved increasing the RTO’s energy offer cap from $1,000/MWh to $2,000/MWh. (See related story, PJM Members OK $2,000/MWh Energy Market Offer Cap.)
The Environmental Protection Agency last week tightened its ground-level ozone limits to 70 parts per billion (ppb), a less strenuous standard than some electric generators had feared and public health advocates had sought.
The National Ambient Air Quality Standards (NAAQS) rule could impact more than three dozen coal-fired electric generators lacking scrubbers or not using them full time.
In areas expected to need to reduce nitrogen oxides (NOx) emissions under the rule, EPA’s Regulatory Impact Analysis identified 37 coal-fired generators that either do not have selective catalytic reduction (SCR) systems (30 units, 5.4 GW) or have the scrubbers but do not always use them (seven units, 3.1 GW).
EPA estimates 358 counties will need to take actions to comply with the new ozone standard of 70 parts per billion. The count does not include California, which has separate standards.
In addition, new generators could be restricted in the more than 350 counties that EPA says will not meet the 70 ppb standard.
Ozone, the main component of smog, aggravates lung diseases, including asthma, emphysema and bronchitis. It forms when emissions of NOx, volatile organic compounds (VOCs), carbon monoxide and methane are heated by the sun. Utilities, industrial facilities, motor vehicle exhaust, gasoline vapors and chemical solvents are the major man-made sources of NOx and VOCs.
Industry Reaction
The agency last visited the issue in 2008, when it released a 75 ppb recommendation. EPA was considering a range between 65 and 70 ppb for an eight-hour average.
The Edison Electric Institute had pushed for a new standard at the top end of the range. “While compliance challenges remain with the new standard at 70 ppb, EPA has recognized the serious implementation concerns raised by stakeholders of setting the standard below 70 ppb,” EEI President Tom Kuhn said in a statement.
The ozone standard doesn’t directly apply to power producers but to their states. David Flannery, legal counsel for the Midwest Ozone Group, said that it’s “too early to tell” how either will be affected. The group represents coal-burning utilities including American Electric Power, Duke Energy and Ameren.
“States will have to decide how they’re going to apply this ambient air standard,” Flannery said. “There’s a mix of sources that contribute. This includes cars and mobile sources in addition to the industrial sources.”
Flannery said that states are still planning how to meet 2008’s 75 ppb rule. “Part of the criticism of the new standard is that the EPA introduced the new standard before the old one could be fully implemented,” he said.
Implementation
EPA said it is tightening the standard based on more than 1,000 recent studies that suggested the current limit did not adequately protect public health.
Assuming it survives anticipated legal challenges, the next step in enforcing the ruling is to designate attainment and nonattainment areas. States will have to suggest designation areas within a year; EPA will make designations by October 2017 using air quality data from 2014 to 2016.
States identified with nonattainment areas will be forced to devise emission inventories and establish a preconstruction permitting program. The preconstruction permits apply to “new or expanding sources of air pollution,” including power plants, industrial boilers and factories.
Any state containing nonattainment areas sorted into the “moderate” or higher category will have until 2021 to design state implementation plans demonstrating the pollution-reducing steps they will take to comply. Deadlines for compliance from nonattainment areas will range from 2020 to 2037.
The agency estimated the new standard will cost $1.4 billion while producing health benefits of $2.9 billion to $5.9 billion.
It says compliance with the new threshold will be made easier by existing environmental rules, including emission control requirements for motor fuels and vehicles, the Mercury and Air Toxics Standards (MATS) and the carbon emission reductions under the Clean Power Plan.
‘Missed Opportunity’
EPA says average ozone levels have dropped 33% nationally since 1980 and that more than 90% of areas designated nonattainment for the 1997 ozone standards now meet those standards. EEI says the electric power sector has reduced sulfur dioxide (SO2) emissions by 80% and NOx by almost three-quarters since 1990 despite increased power demand.
Michael Brune, executive director of environmental advocate Sierra Club, called the rule “a modest step” and “a missed opportunity.”
“Over the past seven years, medical scientists have been clear that any standard above 60 ppb puts our communities at risk and is especially dangerous to children, seniors and people with respiratory illnesses,” Brune said in a statement.
FERC on Wednesday sided with a Long Island power plant developer in its dispute with NYISO over interconnection standards the ISO sought to apply to the company’s proposed 750-MW combined-cycle facility (EL15-84).
The developer of Caithness Long Island II filed a complaint July 10 claiming that NYISO’s application of a local reliability requirement violates its Tariff and FERC Order 2003.
Caithness sought to prevent NYISO from applying the Long Island local reliability interface transfer capability test to identify required system upgrades as part of its interconnection facilities study.
“We find that the Long Island guideline constitutes a deliverability test and therefore using it to identify system upgrade facilities is inconsistent with Order No. 2003 and violates the [Tariff],” FERC wrote.
Order 2003 requires transmission providers to offer two levels of interconnection service: energy resource interconnection service (ERIS) and network resource interconnection service (NRIS). ERIS is a minimal interconnection service and NRIS is a more flexible service for resources that seek to be designated network resources or capacity resources.
To obtain NRIS, the interconnection customer has to satisfy a deliverability test to ensure that its generating facility can be operated simultaneously at peak load along with other generators in the same electrical area and that any output produced above the area’s peak load requirements can be transmitted to other locations on the transmission provider’s system.
The Caithness II project in Brookhaven has proposed an interconnection with the Long Island Power Authority. Caithness had requested basic ERIS service.
Caithness complained that NYISO’s Long Island guideline would allow transmission owners to act unilaterally to cause “an unjustifiable increase in interconnection costs measured in the hundreds of millions of dollars” for the project.
FERC agreed, saying the guideline is “impermissible because it creates a conflict with the NYISO minimum interconnection standard by imposing a deliverability requirement on a project requesting energy-only interconnection under ERIS.”
While NRIS studies are required to identify network upgrades needed to allow the generator to contribute to meeting the overall capacity needs of the control area or planning region, ERIS studies are not, FERC said.
