Entergy has agreed to sell a Rhode Island natural gas-fired power plant to The Carlyle Group for $490 million, a 40% mark-up in less than four years.
Entergy acquired the 13-year-old Rhode Island State Energy Center in Johnston, R.I., from NextEra Energy Resources for $346 million in December 2011. Entergy increased the plant’s capacity from 550 MW to the current 583 MW.
“Our strategy for Entergy Wholesale Commodities is focused on being disciplined about reducing risk and freeing up financial resources for other opportunities,” Entergy CEO Leo Denault said in a statement. “RISEC has been a very good investment for us, and its sale is consistent with that strategy.”
Entergy expects to record a net gain of approximately 50 cents/share assuming closing of the sale occurs in the fourth quarter, it said.
Carlyle insists it is a good deal for it as well.
“RISEC is among the most efficient combined-cycle facilities in New England and is well-positioned to capitalize on strong regional market dynamics. New England represents an attractive market for investment due to its transparency and incentives for reliable generation,” Matt O’Connor, Carlyle managing director and co-head of Carlyle Power Partners, said in a statement. “Additionally, the retirement of aging generation in the region is putting a greater emphasis on efficient gas-fired generators, like RISEC, to meet everyday electricity demand.”
The purchase is being made through Carlyle’s portfolio company Cogentrix Energy Power Management. It increases its power generation portfolio to 18 power plants totaling more than 4,900 MW.
The plant is located in ISO-NE’s constrained Southeastern Massachusetts-Rhode Island capacity zone. The zone failed to meet its capacity requirement in February’s ninth Forward Capacity Auction, which led to the imposition of administrative pricing well above those of resources that cleared at auction. (See Prices up One-Third in ISO-NE Capacity Auction.)
The announcement comes just a few weeks after UBS Global Research downgraded Entergy to sell, based on the prospects for its wholesale commodities unit.
“After the latest disclosures of potential early retirements of Fitzpatrick [838 MW, in New York] and Pilgrim [688 MW, in Massachusetts], we are increasingly concerned about the unregulated plant value,” UBS wrote.
Entergy last month said it may close Pilgrim rather than begin expensive repairs required by the Nuclear Regulatory Commission. (See “NRC Downgrades Arkansas One, Pilgrim Nuclear Plants” in Federal Briefs.)
NRC twice in recent weeks announced deficiencies in the plant’s safety operations. (See “NRC Finds Pilgrim Station’s Weather Tower Inoperable” in Federal Briefs.)
The settlement reached between D.C. Mayor Muriel Bowser and Exelon contains provisions designed to persuade the Public Service Commission to approve the company’s acquisition of Pepco Holdings Inc. If the deal is approved:
Exelon will provide a Customer Investment Fund worth $72.8 million. The fund is broken down as follows:
$25.6 million in rate credits against any future rate increases.
$14 million toward one-time, direct credits to all customers (estimated at $57 per customer).
$3.5 million for a Renewable Energy Development Fund.
$3.5 million paid to D.C.’s Sustainable Energy Trust Fund, which helps residents and businesses use renewable energy, increase energy efficiency and reduce overall energy consumption.
$10.05 million paid to D.C.’s Consumer and Regulatory Affairs Green Building Fund.
$16.15 million toward low-income residential customer assistance: forgiveness of debt that is more than two years old ($400,000); funding to customers eligible for the federal Low Income Home Energy Assistance Program ($9 million); and funding for the district’s energy efficiency programs, such as its home-weatherization program, earmarked for low-income residents ($6.75 million).
Exelon will also contribute $5.2 million to the district’s workforce development programs.
Exelon will move part of its corporate headquarters from Chicago to the district. This includes moving the offices of the CFO and the chief strategy officer. The executives must spend the majority of their office hours in the district.
Exelon will move Pepco Energy Services from Arlington, Va., to D.C.
Pepco will hire at least 102 union workers in the district within two years of the merger’s close.
Pepco must exceed the PSC’s current reliability requirements. Failure to do so will result in self-imposed fines, up to $6 million, paid to the Sustainable Energy Trust Fund.
Pepco will develop an “action plan” to improve its customer satisfaction ratings.
Ring-fencing provisions: “Pepco will maintain its separate existence as a separate corporate subsidiary and its separate franchises, obligations and privileges.” Pepco will not be liable for any debt related to the merger or any future Exelon acquisition. Exelon and Pepco will use “separate legal and government-affairs personnel, support personnel, and separate law firms and consultants to advocate before the commission.”
Pepco, Atlantic City Electric, Baltimore Gas and Electric, Delmarva Power & Light and PECO Energy will remain PJM members until at least the end of 2024. Exelon will also make a one-time contribution of $350,000 to the Consumer Advocates of PJM States.
By the end of 2018, Exelon will develop or assist in developing at least 10 MW of solar generation in D.C. Exelon will also provide $5 million in “capital to creditworthy governmental entities at market rates for the development of renewable energy projects” in D.C.
Pepco will develop and interconnect at least four microgrid projects.
Exelon will enter into power purchase agreements with at least 100 MW of wind energy projects in PJM.
The Market Implementation Committee last week approved rule changes implementing a new Tier 1 resource compensation plan that the group endorsed in July. The changes passed with 28 opposed and 16 abstentions.
The policy requires changes to Manual 11: Energy & Ancillary Services Market Operations; Manual 28: Operating Agreement Accounting; Schedule 1 of the Operating Agreement; and Attachment K of the Tariff.
The revisions will go before the Markets and Reliability Committee for endorsement later this month and to the Members Committee in November. The earliest they would take effect is the beginning of next year.
Under the new compensation scheme, Tier 1 synchronized reserve resources will be obligated to respond in emergencies and subject to penalties if they can’t.
It retains Tier 1’s ability to receive compensation outside of synch reserve events whenever the non-synch reserve market price is more than $0. Units could opt out of the performance obligation, but by doing so they would forfeit any credit they would have received outside of responding to an event.
Estimated Tier 1 megawatts would still be considered when clearing the synch reserve market so that opting out could not be used to withhold supply from the market and drive up prices. (See “Non-Event Tier 1 Credit to Continue, Obligation Added” in PJM MIC Briefs.)
Proposal Would Define Non-Summer DR Capacity Compliance
The committee adopted a problem statement and issue charge to develop a method for calculating customer baselines (CBL) to be used in measuring the compliance of demand response capacity resources in non-summer months.
PJM said new methodology is required under Capacity Performance rules to avoid use of an alternate method requiring two months of load data. “This effort is only focused on how to determine the CBL that will be used to determine non-summer capacity compliance,” the problem statement said.
The problem statement passed with four abstentions; the issue charge with three abstentions.
Fuel Cost Rules Under Development
The Independent Market Monitor said he is developing more complete and better defined rules for generation owners that offer their gas-fired units based on replacement cost.
Monitor Joe Bowring said the new guidelines are needed in light of the experience of the polar vortex and the upcoming rule changes that will permit offers above $1,000/MWh and hourly changes in offers.
“We are not telling generators how to value the gas they purchase. But whatever method you use, we need to be able to verify, a day later or a month later,” he said. “It is critical that verifiable, algorithmic, systematic fuel cost policies be in place to ensure that all gas-fired generators are following the rules when these changes are implemented and that there is no ability to exercise market power.”
PJM Reviews Feedback on Disclosure, Confidentiality
PJM officials reviewed feedback on proposed changes to the RTO’s rules on confidentiality and transparency.
The proposed changes to Manual 33: Administrative Services for the PJM Interconnection Operating Agreement would relax rules barring the release of data such as uplift payments, DR deployments, generator outages and cleared capacity resources. (See PJM Stakeholders to Study Relaxing Confidentiality Rules.)
Under the proposed language, certain information on individual generation outages would be released under a two-month lag.
Some stakeholders cautioned against releasing information they said should remain confidential. Others called for release of information on causes of uplift and for posting cleared capacity by zone.
PJM officials plan to revise the manual language further based on last week’s discussion. No timeline is set for a vote.
The Planning Committee last week approved an increase in PJM’s Installed Reserve Margin despite misgivings by some who said the rise seemed counterintuitive under the RTO’s Capacity Performance program and other efforts to reduce generator outages.
The Reserve Requirement Study results were endorsed by a 100-2 vote with 35 abstentions. It increased the IRM for delivery year 2016/17 to 16.4% from 15.5% in the 2014 study. IRMs also rose for 2017/18 and 2018/19 (see table).
PJM’s Patricio Rocha-Garrido said the increase resulted from changes in capacity and load models as well as a decline in the capacity benefit of ties (CBOT) — the help PJM can expect from imports during peak loads.
The forecast pool requirement (FPR), which determines the amount of capacity procured in the annual Base Residual Auction, also is slated to rise, to 109.52% of peak for 2016/17, up from 108.96%. Rises also are forecast for 2017/18 and 2018/19.
Steve Lieberman of Old Dominion Electric Cooperative said ODEC had too many questions about the methodology to endorse the results. “We don’t understand how, with CP and everything that is required of generators, [PJM’s analysis] will result in an IRM that’s higher,” he said.
Carl Johnson, representing the PJM Public Power Coalition, also abstained, saying stakeholders have repeatedly raised similar criticisms of PJM’s modeling. With the “fundamental change” in capacity assumptions under CP, “It’s probably time for us to undertake a formal process for reevaluating how this is done,” he said.
James Wilson, a consultant to state consumer advocates, presented a harsh critique of PJM’s methodology, saying there was no reason for planners to increase the IRM or FPR.
Wilson said the results were dictated in part by PJM’s “rather arbitrary” choice of the 2003-2012 period for its load model, one of 40 he said it could have selected.
He also disputed planners’ claim that PJM’s and its neighbors’ annual peaks are becoming more coincident. Wilson said PJM’s PRISM modeling software treats all of the RTO’s neighbors as a single “world,” ignoring their diversity.
“PJM is blessed with multiple diverse and substantial neighbors,” he said. “We greatly underrepresent the potential assistance from these neighbors.”
David “Scarp” Scarpignato of Calpine defended PJM’s modeling, saying there were “20 to 30” input assumptions that could increase or decrease the IRM and FPR. “I don’t think the supply side has laid out all the counter” arguments, he said.
Scarp said the IRM is based on meeting summer peaks, while CP was designed in response to problems with generators’ winter performance, including mechanical failures and access to natural gas.
“Calpine is a large gas generation fleet,” Scarp said. “We don’t have problems getting gas during the summer. That’s not changing because of CP.”
Winter Study Criteria, Uplift Added to Planning Manual
Members endorsed PJM’s first criteria for reliability studies focused on meeting winter peaks.
The criteria, outlined in Manual 14B: PJM Region Transmission Planning Process, define the winter peak period as 06:00-09:00 and 17:00-20:00 from Dec. 1 through Feb. 28.
The studies will include thermal and voltage evaluations; solutions to identified problems will be developed through the Transmission Expansion Advisory Committee.
The criteria will be effective for baseline studies on Jan. 1 and for interconnection queue requests received after the effective date of the revised manual language. The criteria are scheduled to be considered by the Markets and Reliability Committee on Oct. 22.
Members also endorsed a separate change to Manual 14B, adding energy market uplift payments as an issue to be considered in the planning process when developing transmission upgrades for operational performance.
Task Force to Seek Fix for Late Filings in Interconnection Queue
Members endorsed the charter for the Earlier Queue Submittal Task Force, which will seek new ways to discourage late entries into the interconnection queue.
PJM had instituted an escalating filing fee in an effort to encourage generators to file their interconnection requests earlier, but the change was “complicated and ineffective at dissuading late entry,” the RTO said. The influx of 11th-hour entries results in a higher proportion of deficient filings and interferes with planners’ ability to start feasibility analyses. (See PJM to Try Again to Speed Interconnection Filings.)
The group, which will be facilitated by PJM’s Andrew Gledhill, will seek a solution that could be implemented by May 1, 2016.
FirstEnergy Removing Black Oak SPS
FirstEnergy is removing the special protection scheme for the Black Oak 500/138-kV #3 transformer.
The scheme was put in place in 2010 after PJM identified potential overloads with the loss of the Black Oak-Hatfield 500-kV line.
FirstEnergy said the scheme is no longer necessary because of generation retirements, the rerating of the transformer in 2012 and completion of the Trans-Allegheny Interstate Line (TrAIL).
FERC last week scheduled a technical conference for Nov. 12 to examine how PJM determines whether solutions to local transmission needs should be part of the regional transmission plan and opened to competitive proposals under Order 1000.
It also will examine how the RTO and its transmission owners identify local transmission needs (ER15-1344, ER15-1387).
The commission ordered the conference Sept. 15 in response to PJM’s filing seeking approval of the cost allocations for 61 baseline upgrades added to its Regional Transmission Expansion Plan (ER15-1344).
The conference also will address issues raised by rehearing requests filed over the TOs’ proposal to change the cost allocation for reliability projects selected in the RTEP solely to address local transmission owner planning criteria (ER15-1387-001).
In March, Dayton Power & Light protested the cost allocation of a $106 million transmission project by Dominion Resources that was included in the 2015 RTEP. The 500-kV Cunningham-Elmont end-of-life project (Project b2582) initially was designated a supplemental proposal, for which Dominion, as the incumbent utility, would bear the full cost.
But after changing its local planning criteria last year, Dominion asked PJM to study the need for the project and received permission to change its designation to baseline, categorizing it as a new line and allowing the company to reduce its costs by more than half. (See DP&L Protests Dominion Project over New Cost Allocation.)
A supplemental project is one that is not required for compliance with state public policy or PJM system reliability, operational performance or economic criteria.
PJM: No Policies for Reclassifying Supplemental Projects
FERC issued PJM a deficiency letter in June seeking more information on the RTEP filing.
In its response, PJM acknowledged that there are no provisions in its Tariff, Operating Agreement or manuals that explain how the RTO re-categorizes a supplemental project to a baseline upgrade that is eligible for regional cost allocation. Nor is there any documentation that describes the process by which a transmission owner updates its local planning criteria, PJM said.
In its September order, FERC said that PJM’s RTEP filing and deficiency letter response raised issues that could not be resolved based on the record before it.
“Although we are establishing a technical conference, we do not find merit in Dayton’s argument for rejecting the cost assignment for project b2582,” the commission said. “The record indicates that Dominion followed the appropriate procedures to update its local planning criteria. Specifically, after Dominion presented its proposal to add end-of-life criteria to its individual transmission planning criteria at a PJM Planning Committee meeting, Dominion adopted the proposed criteria in its FERC Form No. 715.
“Thus, Dominion’s revisions to its individual transmission planning criteria will not be discussed at the technical conference. Instead, the technical conference will focus on PJM’s application of its Order No. 1000-compliant planning procedures, including PJM’s process for opening proposal windows.”
The commission said the conference also will examine concerns regarding how PJM plans for local transmission projects, including PJM’s “process for soliciting, identifying and selecting the more efficient or cost-effective regional transmission solutions for all needs for purposes of cost allocation.”
Inuit Association Seeks Nunavut Interconnection to Manitoba System
The Kivalliq Inuit Association says connecting its remote electric grid in the far northern, and sparsely populated, territory of Nunavut to Manitoba’s hydroelectric power would be a win for the region, despite the estimated $904 million cost.
An engineering study commissioned by the association said that construction of a transmission line from Churchill, Manitoba, up the western Hudson Bay coast would allow Nunavut to replace costly diesel generation with Manitoba hydroelectric power. The project would save $40 million a year and pay for itself over the course of its 40-year lifespan.
“Ever since I’ve been elected I’ve been pushing for this,” said Joe Savikataaq, Arviat-South member of the Legislative Assembly of Nunavut. “Our power plants are aging and the amount of diesel our communities can hold has to be expended.”
ComEd Project Aims to Boost Use of Demand Response
A pilot project in Chicago aims to demonstrate that demand response can be a year-round resource able to compete in PJM’s capacity market.
The Combined Capacity Asset Performance Project will combine renewable energy like wind and solar with the DR capability of several Chicago buildings. It is being led by PJM, the Environmental Defense Fund, the Accelerate Group and the Citizens Utility Board.
Under previous market rules, suppliers of DR could choose to participate only in the summer months. New PJM rules require that resources be able to respond whenever there is a critical need.
Suburu Blames High Power Prices for Advantage Loss
Automaker Subaru says that the state’s increasing power prices are causing its Lafayette assembly plant to lose its competitive advantage.
Industrial electricity prices in the state have risen 75% between 2003 and 2015, about twice the national rate, according to U.S. Energy Information Administration data. The state had the fifth lowest industrial electricity prices in the nation in 2003, but today 25 states offer lower pricing.
The Indiana Energy Association blames the rise in the state’s industrial electric rates on federal environmental regulations, which have hit the state’s coal-fired power generators. Industrial leaders are pressuring policymakers to allow for the increased use of on-site cogeneration.
Renewable Tax Credits Sitting Idle in Developers’ Hands
Renewable energy developers are failing to build many projects for which production tax credits have been set aside, according to Midwest Energy News.
A study of Utility Board records shows that 113 proposed wind projects were assigned the production tax credits but were never constructed. The study showed that 37 of those were approved in 2009 but received repeated 12-month extensions. Nineteen other proposed wind projects were on standby because the tax credits had already been assigned.
“There are a few projects that I think are ready to go, and are on the waiting list, and projects ahead of them may never be built,” said Nathaniel Baer, energy program director for the Iowa Environmental Council. Baer called for “a fresh look” at the projects if they haven’t been built years after getting awarded the credits.
Kansas Municipal Utilities to Open Training Center
Kansas Municipal Utilities broke ground last week on a $3.2 million workforce training center in McPherson. The center is due to open in June 2016 and is the only one of its kind in a multistate area.
The project is answering the call from Kansas Municipal Utilities’ 176 members, which have aging workforces. The training center would not serve rural electric cooperatives or investor-owned utilities.
The Public Service Commission is exploring whether to allow net metering. The state is one of five that do not require utilities to buy surplus power produced by customer generators.
At a two-hour hearing last week, supporters of the proposed net-metering rules say they would benefit all utility customers, while utilities expressed concern that the rules would shift costs to non-producing customers. State regulators are also considering whether it has the authority to order member-owned cooperatives to abide by net-metering rules.
Commissioners extended the comment period, and it’s not clear when they will vote on the issue, which they’ve been considering since 2011.
State Energy Plan Calls for Wind Incentives, More Renewables
The state’s new Comprehensive State Energy Plan, released last week during the Midwest Energy Policy Conference in St. Louis, recommends adopting a building code, requiring power companies to offer efficiency programs and boosting the amount of renewable energy utilities have to offer their customers.
Gov. Jay Nixon launched the effort last year. The Division of Energy has spent more than a year meeting stakeholders. What emerged is a plan calling for incremental changes that will give the state time to adapt.
The Division of Energy says the plan is unrelated to efforts to comply with the federal Clean Power Plan. The plan does offer dozens of policy recommendations on everything from better energy education to complex changes in utility regulations.
TransCanada, the company seeking to build the Keystone XL Pipeline, is withdrawing its eminent domain claims on the land it planned to use for the pipeline and will instead go to the state’s Public Service Commission for route approval.
The company’s decision came on the eve of the state trial on the eminent domain issue, which was scheduled to start Oct. 19. Even if it had prevailed in state court, TransCanada would have still had to get approval from the PSC to go forward.
“The writing’s kind of on the wall,” said University of Nebraska law professor Anthony Schutz. “The prospect of losing was significant enough that they probably looked at the tea leaves and said, ‘Why don’t we just go forward with that process now?’ ”
Facing a shortfall to pay for retirement benefits, Nebraska Public Power District is asking its biggest wholesale customers for more money. However, 10 local power districts and cities are speaking out against a proposal they say is discriminatory, unfair and even outlandish.
NPPD says it needs $25 million more a year to address a shortfall in its retirement fund. It is asking for a 3.85% increase in the wholesale rate. However, those that sign a new contract will get a discount, so their increase would be just 0.6%.
A handful of cities and power districts are abandoning the public power supplier and shopping for electricity from other producers, which NPPD CEO Pat Pope says he did not anticipate.
Gov. Maggie Hassan will not reappoint Susan Chamberlin, the incumbent consumer advocate on utility issues. Opponents of a Kinder Morgan natural gas pipeline project, who see her as an ally in proceedings before the Public Utilities Commission, are upset by the move as well as delays in finding her replacement.
State officials have known since July that Chamberlin, whose term expires Nov. 5, was not likely to be reappointed. “The dismissal of one of the most powerful advocates for New Hampshire residents, and the significant delay in nominations for a replacement, is a telling lack of concern for all of New Hampshire ratepayers,” said Maryann Harper, a spokesperson for the Pipeline Awareness Network of New Hampshire.
The decision regarding Chamberlin was the result of a review in which the committee received confidential, anonymous feedback from managers, peers and direct reports that were not favorable enough to lead to a reappointment.
Kinder Morgan announced Thursday that it is exploring a modification to the proposed Northeast Energy Direct pipeline route in Merrimack. Barry Duff, project manager, said the company met with officials from two businesses about some newly proposed amendments.
“I am happy that the businesses are being listened to,” said Jody Vaillancourt, Town Council member. However, she maintained the community is at a huge disadvantage because new modifications are being introduced in the final hours.
Kinder Morgan said the original route was amended and moved farther to the east to minimize impact to a nearby school and to avoid conservation land.
Public Service Company of New Mexico and the state’s Attorney General’s Office are challenging an advocacy group’s allegations that PNM manipulated numbers to justify the company’s plans for the coal-fired San Juan Generating Station. PNM proposes to close two of the plant’s four coal-fired units and replace the lost capacity from other sources, including coal-generated power from another unit at the plant.
David Van Winkle, an expert for Santa Fe-based New Energy Economy, last month filed written testimony claiming PNM significantly understated the size of rate increases the utility would seek during the next 20 years if the state’s Public Regulation Commission approves its plan.
PNM’s Patrick O’Connell last week filed a response that said the consultant’s “derogatory and inflammatory accusations about PNM’s alleged manipulation of data to achieve a ‘predetermined’ result are totally false.” Andrea Crane, a consultant from The Columbia Group, a Connecticut-based firm specializing in utility regulation that is contracted with the Attorney General’s Office for cases involving utilities, also filed a rebuttal last week.
Long Island Officials Challenging PSEG Rate Increase
Elected officials are asking for a halt to PSEG Long Island’s rate increase hearings, saying the rate case is flawed because of “constitutional and contractual” concerns.
The request comes a week after the Long Island Power Authority tentatively approved a $325.4 million rate increase. The increase still needs a final vote. In a letter to the state Department of Public Service, 12 Long Island Republican state assemblymen contend that there is “no true oversight” over PSEG and that the LIPA board lacks “objectivity and expertise.”
PSEG, which originally sought a $387 million increase, said it followed the rate increase request process dictated by the 2013 LIPA Reform Act.
NCWARN, a solar advocacy group, installed a solar facility atop a Greensboro church and is selling the power directly back to the church, bypassing area utility Duke Energy. The move is intended to create a test case for state regulators.
The organization says it entered into a three-year contract to sell the power directly to the church as a way to spur a ruling on what it sees as Duke’s monopoly on direct sales to customers. Current law requires the owners of a solar facility to either use the power themselves or sell directly back to the area utility.
NCWARN earlier this year built a 5.2-kW solar project on the roof of Faith Community Church and signed a three-year agreement to sell the power back for 5 cents/kWh, about half the rate charged by Duke. NCWARN is asking the state Utilities Commission to rule that the three-year arrangement is legal.
Staff: PUCO Should Reject AEP Profit-Guarantee Plan
Public Utilities Commission staff have recommended that the commission reject American Electric Power’s proposal that would guarantee profits at some of its power plants.
“Staff recommends that the commission deny the [proposal] as it is currently proposed,” said Hisham Choueiki, a senior energy specialist for PUCO. “However, it is possible that the [proposal], if properly conceived, may be in the public interest.”
Last month, staff recommended that the commission reject a similar proposal from FirstEnergy. AEP has said its plan will help to reduce volatility in electricity pricing and preserve jobs at power plants that may otherwise close.
State is Likely to Meet Stricter Ozone Regulations
The state is expected to comply with the Environmental Protection Agency’s recently unveiled tighter limits for ground-level ozone. Officials were still studying the new standards, but the Department of Environmental Quality said the state likely would fall under a three-year period that includes monitoring data from 2014-2016.
Based on monitoring data from 2013 and into 2015, all counties would meet the new standard of 70 parts/billion, said ODEQ spokeswoman Skylar McElhaney.
Bud Ground, environmental and regulatory affairs consultant with the Oklahoma Oil and Gas Association, said the new limits could put Oklahoma City and Tulsa counties closer to non-attainment status and wouldn’t leave much room for variation in years with hot summers, nor would it account for smog coming over the border from Texas.
Goliad County has set aside tax revenue collected in 2014 from Coleto Creek Power because the power company is embroiled in a lawsuit with the county’s tax appraisal district. The company is challenging the plant’s tax valuation. It was assessed at $353.7 million in 2014 and $403.9 million this year.
Coleto Creek Power claims that the 35-year-old coal-fired plant “has faced dramatic adverse developments” due in part to a newfound abundance of natural gas at low prices. The 632-MW plant also has to contend with stricter emissions requirements and is spending more to transport coal from Wyoming to Texas because a railroad agreement has expired.
Legislation that became effective Sept. 1 requires counties to repay tax revenue back with 9.5% interest, according to the county judge. The next court date is in May.
Hearing Requests Withdrawn for North Texas Gas Plant
Van Alstyne residents have withdrawn their requests with the Commission of Environmental Quality for a formal hearing of a proposed Navasota Energy power plant.
In September, some residents named themselves as affected parties of Navasota Energy’s plans to build just outside the town’s city limits. That would have required Navasota officials to secure an air-quality permit from TCEQ.
A TCEQ spokesperson said that because the affected parties had withdrawn their requests, the commission now anticipates the matter will come back to the commission as uncontested.
More Wind Farms Likely as Part of ‘Energy Revolution’
The wind industry held a two-day conference to promote renewable energy, which attracted several dozen protesters who warned that large-scale mountaintop wind turbines are a poor match for the state.
Gabrielle Stebbins, executive director of Renewable Energy Vermont, the trade group that hosted the two-day conference, said the state’s “energy revolution” is picking up speed, investment and credibility. That momentum will very likely include the ridge-top development of more large-scale wind projects, she said.
The group outside waved signs reading “ridgelines are not renewable,” “stop destroying Vermont,” “no wind turbines” and “save the ridge.”
Republican lawmakers in the state are trying to end a 1983 ban on new nuclear construction. Bills sponsored by Sen. Frank Lasee of De Pere and Rep. Kevin Petersen of Waupaca would waive the Public Service Commission’s requirement that a waste repository be in place in order to approve new nuclear generation.
Similar bills were introduced in 2005 and 2009 but did not advance. With the 2013 closure of Dominion’s Kewaunee nuclear station, the only operating nuclear generating station in the state is NextEra’s Point Beach facility. Dairyland Electric Cooperative’s La Crosse Boiling Water Reactor in Genoa was shut down in 1987 and is in the midst of decommissioning.
Former Louisiana Sen. Mary Landrieu, now a lobbyist, has signed her first client: FutureGen Alliance, the company behind a currently failed clean-coal project.
FutureGen Alliance is a coalition formed to research and develop a coal-fired power plant that would capture carbon dioxide and entomb it underground. Its Illinois project, FutureGen 2.0, received millions of dollars in government stimulus support but never got off the ground after Illinois lawmakers declined to finance the additional $1.7 billion it said it needed. The Department of Energy has since withdrawn its support.
While environmental groups applauded its death, Illinois Sen. Dick Durbin was sorry to see it go. “This is a huge disappointment for both Central Illinois and supporters of clean-coal technology,” he said at the time.
Obama Appoints EPA Strategist to Run Climate Change Campaign
Thomas Reynolds, a top Environmental Protection Agency communications strategist, has been named to a new White House position and will run the Obama administration’s climate change agenda.
Reynolds is seen as an aggressive communications strategist and is the architect of EPA Administrator Gina McCarthy’s nationwide tour to promote the agency’s new climate rules. He has also directed the energetic social media campaign around the Clean Power Plan.
Before signing on with EPA, Reynolds was a regional media director for Obama’s 2012 re-election campaign.
The U.S. Energy Information Administration said that in July, for the second time ever, more power was generated by natural gas-fired plants than by coal-fired plants in the U.S. The administration said that natural gas-fired plants generated 35% of U.S. power in July, compared to 34.9% from coal.
Compared to the same period a year ago, coal fell from 150 billion kWh to 139 billion kWh. Natural gas generation increased from 114 billion kWh to 140 billion kWh. The report said natural gas generation has been increasing its share because of the abundance of low-cost shale gas, in addition to more stringent federal emission regulations affecting coal-fired plants.
The first time natural gas edged out coal-fired generation was in April.
Fed Court Rules Obama’s Waterway Protection Bid Can’t be Enforced
A U.S. Court of Appeals in Ohio ruled Friday that the Obama administration’s regulation to protect small waterways from pollution cannot be enforced throughout the country. A 2-1 majority decided the “Waters of the United States” rule is likely illegal and stayed the rule so it can be reviewed.
“We conclude that petitioners have demonstrated a substantial possibility of success on the merits of their claims,” the judges wrote in their decision, explaining that the Environmental Protection Agency’s guidelines run counter to an established Supreme Court ruling. The appeals court said a stay would be appropriate and provide an opportunity to review the jurisdictional issues.
“A stay allows for a more deliberate determination whether this exercise of executive power, enabled by Congress and explicated by the Supreme Court, is proper under the dictates of federal law,” the court said. The decision comes after a North Dakota judge in August issued a similar ruling.
FERC last week gave Spectra Energy permission to begin construction on a project to expand the Algonquin Pipeline into the Northeast. The agency approved a construction start on the AIM portion of the project, a 37-mile section that will run under the Hudson River and into Connecticut, along with two compressor stations.
The pipeline, which will eventually connect Connecticut, Rhode Island and Massachusetts, is designed to deliver additional natural gas into a region that experienced winter shortages due to pipeline constraints.
DOE: Solyndra Filed Misleading Reports in Bid for Loan
Solyndra, the failed California thin-film solar company, provided misleading documents when applying for a Department of Energy loan guarantee, according to a department report.
The investigation found that Solyndra “provided the department with statements, assertions and certifications that were inaccurate and misleading, misrepresented known facts and, in some instances, omitted information that was highly relevant to key decisions in the process to award and execute the $535 million loan guarantee.”
The report also noted that department employees who approved the loan didn’t conduct sufficient due diligence. Solyndra shut down in 2011, leaving the federal government on the hook for the unpaid loan.
House Passes Bill to Speed Up Tribal Energy Projects
The House of Representatives approved a bill that would streamline the federal permitting process for energy projects on tribal lands. The White House and many Democrats oppose the bill, which the Office of Management and Budget said would undermine the energy permitting process by removing federal oversight.
The bill, introduced by Rep. Don Young (R-Alaska), cuts back on the permitting procedure for leases signed for energy projects on Native American land. Currently, the Department of the Interior reviews each lease signed by a tribe with an energy company.
“We are doing an indirect thing to allow them to … expand their self-worth and keep their identity,” Young said.
National Grid Finds Nobody in Favor of Liquefaction Plant
A FERC-sponsored comment session on National Grid’s plan to build a $100 million methane liquefaction plant in Rhode Island attracted many commenters, but none who support the project.
The plant, proposed for a site in southern Providence, is before FERC for a permit. The comment session drew about 100 spectators, and 33 spoke out against the project. FERC is also accepting written comments on the project.
Talen Energy last week announced the sale of three Pennsylvania power plants for $1.51 billion to help satisfy regulators’ demands to divest assets in PJM.
The 704-MW combined-cycle Ironwood plant is being sold to a subsidiary of Calgary-based TransCanada for $654 million. The Holtwood and Lake Wallenpaupack hydroelectric projects, with a combined generating capacity of 292 MW, are being sold to a subsidiary of Quebec-based Brookfield Renewable Energy Partners for $860 million.
FERC had ordered the divestiture when it approved the company’s formation from the generation assets of PPL and Riverstone Holdings last year. Talen, which had proposed two divestiture packages, last month offered a third option that included the three plants it is selling in addition to the Charles P. Crane coal-fired plant in Bowleys Quarters, Md. (See Talen Seeks Change in Divestiture Options.)
However, the company didn’t wait for FERC to rule on the new request. “We had very attractive offers for those three assets and we decided to move forward at this time,” spokesman George Lewis said.
“We’re not done yet,” Lewis added, saying Talen is evaluating offers for the 399-MW Crane plant and six former Riverstone generators in New Jersey that were part of the first two divestiture options.
The transactions announced last week are expected to result in net proceeds of approximately $1.16 billion. Talen said it plans to use the proceeds to retire pre-payable and maturing debt, positioning it for acquisitions outside the Mid-Atlantic. Both transactions are expected to close in the first quarter of 2016, pending regulatory approvals.
In a research note, UBS Global Research said the Ironwood sale was in line with expectations at an enterprise multiple (enterprise value divided by earnings before interest, tax, depreciation and amortization (EBITDA)) of 8.
But the hydro purchase price represented an EV/EBITDA of 18, about $200 million more than Wall Street expectations. “After factoring in tax obligation on the sale, we see the transaction as adding +$2/[share] in value assuming debt paydown,” UBS said.
Brookfield said the hydro assets were complementary to its 417-MW Safe Harbor facility 8 miles upstream from Holtwood. Holtwood and Wallenpaupack are licensed through 2030 and 2045, respectively.
“These high-quality assets provide a unique opportunity to leverage our operating platform and hydroelectric expertise in a market facing significant coal retirements and increasing reliance on renewables,” Brookfield CEO Sachin Shah said.
Including the Talen sale, Canadian companies have agreed to purchase $11.7 billion in U.S. utility and power assets this year, Bloomberg reported.
Analysts say U.S. utility assets are more profitable than those in Canada. If Canadian utilities want to grow, “it’s going to be on the acquisition side, and there’s a lot more opportunity in the States,” Rebecca Hazan, a fund manager at Leon Frazer & Associates, told Bloomberg.
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.
Entergy expects to record a net gain of approximately 50 cents/share assuming closing of the sale occurs in the fourth quarter, it said.
