ERCOT’s latest resource adequacy assessments indicate it has 25,000 to 30,000 MW of spare generating capacity for the fall and winter.
ERCOT’s control rom Source: ERCOT
The Texas grid operator’s final Seasonal Assessment of Resource Adequacy (SARA) for October and November includes more than 82,000 MW of capacity, more than enough to meet a projected peak demand of about 54,400 MW.
The preliminary winter SARA report is similarly rosy, with more than 81,000 MW of capacity available to meet a forecasted record peak demand just under 59,000 MW. The winter demand record of 57,265 MW was set during February 2011’s record cold.
ERCOT, which operates 90% of the Texas grid, said four gas-fired combustion turbine units and three wind projects have begun operating since its preliminary fall SARA, adding nearly 900 MW of capacity. Three of the gas units are switchable resources and can connect to either ERCOT’s or SPP’s grids. The fall forecast assumes 13,700 to 19,000 MW of planned and unplanned outages.
Another 1,200 MW of new winter-rated capacity is expected to be in service for the winter season (December-February). The final winter SARA report will be released in November.
PJM’s Independent Market Monitor last week gave his blessing to the RTO’s Base Residual Auction for delivery year 2019/20 but called for additional rule changes to build on the tougher standards of Capacity Performance.
The Monitor’s report on the May auction concluded that the results “were competitive, with the caveat that although the Capacity Performance design addressed the most significant issues with the capacity market design, the Capacity Performance design was not fully implemented in the 2019/2020 BRA and there continue to be issues with the capacity market design which have significant consequences for market outcomes.”
PJM will require all capacity to meet CP standards starting with the 2020/21 delivery year.
The Monitor called for additional changes concerning the treatment of pseudo-tied generation, demand response and energy efficiency; the calculation of net revenues; and the application of the minimum offer price rule (MOPR).
The Monitor also acknowledged that its call for using the lower of the cost- or price‐based offer in the calculation of net revenues was rejected by FERC in June (EL14-94-001, ER16-1291). (See “FERC Won’t Revisit Cost-Based Energy Offer Cap Ruling,” PJM News Briefs from FERC Open Meeting.)
But he said the FERC-approved approach used in the May auction, which always uses the cost‐based offer, “resulted in an increase of [$43.4 million], or 0.6%, in the cost of capacity in the 2019/20 BRA.”
In addition, the Monitor recommended:
All costs incurred as a result of a pseudo-tied generator be borne by the unit and included in its capacity market offers.
The “electrical proximity” of pseudo-tied resources be “explicitly accounted for” when defining how external resources should be treated during performance assessment hours.
Enforcing “a consistent definition” of capacity resource as a physical resource at the time of the auctions — with a commitment to be physical in the delivery year and moving all DR to the demand side of the market. The Monitor referenced its 2013 report on replacement capacity, in which it warned that “speculative” DR can suppress prices in the BRA and displace physical generation: “Under the current application of the rules, DR providers may not have identified customers, may not have clear plans for implementing DR measures and may not receive commitments from new customers until relatively close to the delivery year and well after the RPM BRA is run for that delivery year. This is not consistent with the rules.”
Ensuring the net revenue calculation used to establish the net cost of new entry “reflect the actual flexibility of units in responding to price signals rather than using assumed fixed operating blocks that are not a result of actual unit limitations.” Reflecting actual flexibility will result in higher net revenues, which affect the demand curve and market outcomes, the Monitor said.
Eliminating the rule requiring that small proposed increases in the capability of a generator be treated as planned for purposes of mitigation and exempted from offer capping.
Changing the MOPR review to require all projects use the same modeling assumptions. “That is the only way to ensure that projects compete on the basis of actual costs rather than on the basis of modeling assumptions,” the Monitor said.
Extending the MOPR to existing units in addition to new units.
Re-evaluating the market mitigation exemption granted DR and energy efficiency resources in 2009. “In 2009, there was one product defined for capacity, and there were no resource constraints defined,” the Monitor said. “Particularly in [locational deliverability areas] with few suppliers, there is now the potential for DR and EE providers to exercise market power and affect the clearing price.”
Changing the RPM solution methodology to explicitly incorporate the cost of make-whole payments in the objective function.
Removing energy efficiency resources from the supply side of the capacity market to reflect the change in PJM’s load forecasts. (See Changes to PJM Load Forecast Cuts Benchmark Peaks.) “If EE is not included on the supply side, there is no reason to have an add-back mechanism,” the Monitor said. “If EE remains on the supply side, the implementation of the EE add-back mechanism should be modified to ensure that market clearing prices are not affected.”
FERC on Wednesday rejected Algonquin Gas Transmission’s request to exempt gas-fired generators from competitive bidding under capacity release rules, another blow to those seeking to increase New England’s gas infrastructure (RP16-618).
Photo credit: Steve Oehlenschlager
The proposal to amend Algonquin’s tariff was an offshoot of the company’s proposed Access Northeast pipeline. Electric distribution companies Eversource Energy and National Grid — which are partnering with Algonquin on the pipeline — sought the exemption to ensure the capacity they purchased would be used to fuel gas-fired generators.
The EDCs hoped to release capacity to gas generators as prearranged “replacement” shippers. FERC rules allow such preferences as long as the replacement shipper matches the highest bid submitted by any other bidder. The proposal would have limited that bidding to gas-fired generators, excluding those who might value the fuel more for winter heating.
The proposal was opposed by numerous merchant generators, including NextEra Energy, Exelon and Calpine, which said they had found cheaper alternatives to ensure fuel supplies under ISO-NE’s Pay-for-Performance capacity incentives, including installation of dual-fuel capacity and contracts with natural gas marketers and LNG suppliers.
“Merchant generators are not asking you for this capacity, and you need to ask yourself why,” Calpine told FERC. The company estimated firm capacity would cost it $25 million annually, or half a billion dollars over a 20-year commitment. It said it could guarantee the same level of service by investing $50 million in a fuel oil tank.
Other opponents argued that the proposal was premature because no state had approved a state-regulated electric reliability program.
“Neither Eversource nor National Grid provided a persuasive explanation for why the ability to release capacity to a prearranged replacement shipper under our existing regulations is not sufficient to meet their needs,” FERC ruled. “Moreover, neither party sufficiently explained why a generator that needed the capacity to obtain the natural gas supplies necessary to generate electricity during a period when Algonquin’s capacity is constrained would not match a higher bid.”
However, the commission said its ruling was “without prejudice to Algonquin developing other more targeted, justified proposals for consideration.”
The commission also granted Algonquin’s request to exempt from bidding an EDC’s capacity release to third parties managing capacity on an EDC’s behalf.
“By permitting capacity holders to use third-party experts to manage their natural gas supply arrangements and their pipeline capacity, [asset management arrangements] provide for lower gas supply costs and more efficient use of the pipeline grid,” the commission said. A compliance filing on this proposal is due in 30 days.
Access Northeast suffered a setback in August when the Massachusetts Supreme Judicial Court overruled state regulators’ order to allow construction costs be assessed to electricity ratepayers. Soon after the ruling, the EDCs withdrew their proposed contracts that were pending before the Massachusetts Department of Public Utilities. (See Eversource, National Grid Withdraw Requests to Bill for Pipeline.)
Access Northeast Complaint Dismissed
In a related case, FERC dismissed a complaint filed by electric generators seeking to block EDC contracts with pipeline owners as premature (EL16-93).
“The circumstances giving rise to the complaint are in a state of flux and the commission does not have before it the concrete facts necessary to determine whether the tariff will be unjust and unreasonable. Several critical project elements of the individual states’ electric reliability programs are undetermined at this time,” FERC wrote.
The commission cited the Massachusetts court ruling, its concurrent order on capacity releases and its pending ruling on Access Northeast, which is expected in the fourth quarter.
The newly established Western Energy Imbalance Market (EIM) governing body kicked off its first meeting last week by electing its leadership.
CAISO’s Board of Governors appointed the five-member body in June, selecting one each from five industry sectors: EIM entities, ISO-participating transmission owners, power suppliers and marketers, publicly owned utilities and state regulators. (See CAISO Board Appoints Western Energy Imbalance Market Governing Body.)
Kristine Schmidt, president of Dallas-based Swan Consulting, was selected to serve as the body’s chair. A former vice president at ITC Holdings and director at Xcel Energy, Schmidt has more than 30 years’ experience in the energy sector. She also worked as an adviser to former FERC Commissioner Nora Brownell.
The EIM Governing Body selected Kristine Schmidt and Doug Howe as its chair and vice-chair, respectively.
Doug Howe, an independent consultant and Ph.D. in mathematics, was chosen as vice chair. Howe has authored or co-authored more than 30 papers and presentations covering industry topics such as energy efficiency in the European Union and utility regulation in the U.K. He previously held an executive position with GPU Inc., which was acquired by FirstEnergy in 2001.
Carl Linvill, a member of the governing body, praised Schmidt for her “equanimity” and also expressed support for the wider Western regional representation that Howe — a New Mexico resident and former state regulator — will provide.
“We still have a lot to figure out and learn,” Linvill said. “Figuring out how to establish a regional presence really is emboldened and enabled by these two positions.”
“On behalf of the ISO, we want to give you our immense thanks for being willing to serve on this body,” CAISO CEO Steve Berberich said. “We consider the EIM as a critical attribute and will continue to support it for as long as necessary.”
A decade ago, Schmidt noted, nobody in the industry would’ve believed the region would have an EIM.
“We’re now seeing a regional market take shape in the West,” Schmidt said. “We’re hitting the ground running.”
Stakeholder Coordination
The governing body’s inaugural meeting included a set of briefings by EIM stakeholders and ISO staff to acquaint members with key structures affecting the market.
“There’s a lot of interest in what you’ll be doing,” said Tony Braun, an industry consultant who chairs the Regional Issues Forum, a loosely structured stakeholder group created by CAISO to foster broad regional discussion about EIM-related issues.
While the forum’s role “has not been concretely laid out,” the group’s first two meetings have been well attended, indicating a high level of interest in the EIM’s activities, Braun said.
The two most significant issues for forum participants: the bidding of external resources at the EIM’s interties and the impact of California’s greenhouse gas regulations on the market. (See related story, CAISO Kicks off Effort to Track GHGs Under Regionalization.)
Braun proposed that future meetings of the forum be coordinated with those of the EIM’s governing body and its state regulators’ group to improve collaboration and reduce participants’ travel for meetings.
“We’d love to hear how we can shape our processes to help you do your jobs,” Braun said.
Governing body members expressed appreciation for the work of the forum.
“The stakeholder-driven nature of the [forum] is probably something that is both difficult and necessary,” said governing body member Valerie Fong. “I found that the way [the meetings are] being run is very open.”
Schmidt called the meetings “extremely helpful.”
“We’re trying to do everything we can do to mitigate some of the travel issues,” she added.
Regulatory Collaboration
Ann Rendahl, chair of the EIM’s body of state regulators, sketched out the role of her group for the new governing body.
“Our purpose is to ensure that state regulators that aren’t involved in this market understand what is going on in EIM,” said Rendahl, a member of the Washington Utilities and Transportation Commission.
The group provides a forum for regulators to learn about EIM and CAISO developments that might be relevant to their jurisdictional responsibilities. While it can take a common position in CAISO and EIM stakeholder processes, individual regulatory commissions are not restricted from taking any position before FERC or the ISO board on EIM-related matters.
The regulators’ group is also charged with monitoring EIM governing body action items and selecting a voting member for the body’s nominating committee.
Rendahl emphasized the need for her group to closely coordinate its activities with that of the governing body. “We want to not just monitor, but work with the governing body,” she said.
ISO Process Basics
Governing body members received a briefing about CAISO’s stakeholder process from Brad Cooper, ISO manager of market design and regulatory policy.
Cooper explained the stakeholder process the ISO uses each fall to develop a “roadmap” of planned policy developments, including EIM initiatives. The ISO last year drew from a catalog of 49 potential initiatives, selecting only 10 because of staff constraints.
“We can’t develop everything in the catalog,” Cooper said.
A final roadmap is presented to the CAISO board — and, in the future, the EIM governing body — at the beginning of each year. The ISO informs stakeholders of any changes to the roadmap through its Market Performance and Planning Forum.
“The roadmap isn’t set in stone,” Cooper said. “For instance, we had the Aliso Canyon issue come up” earlier this year, forcing a modification of the roadmap. (See CAISO Seeks Rapid Response to SoCal Gas Restrictions.)
When developing the roadmap, ISO staff divide initiatives into four categories, including initiatives already in progress, policy changes mandated by FERC, non-discretionary efforts related to reliability or market efficiency, and discretionary initiatives.
For the last category, ISO staff and stakeholders together prioritize potential initiatives according to benefits and feasibility.
“If something could provide great benefits and is relatively trivial to do, that would get priority,” Cooper said.
Cooper acknowledged that CAISO’s policy process is driven more by staff than by stakeholders — and said the ISO prefers it that way.
“We realize that we made a commitment to look at other [stakeholder] processes [to implement under] regionalization, but we think our stakeholder process really allows us to quickly evolve policies,” Cooper said, adding that he didn’t think a project such as the EIM could’ve been developed under a stakeholder-led model.
“The ISO really tries to take a balanced view of our proposed policy,” Cooper said, contending that the ISO’s process does not factor in specific stakeholder interests, avoids “contentious voting structures,” and prevents bias or brokered policy decisions — allowing the ISO to focus on grid reliability.
Still, Cooper emphasized that “stakeholders are involved every step of the way,” including through “working group” meetings that focus on specific initiatives.
“We have a lot of open interaction that may not be possible with more formal stakeholder processes,” Cooper said. “This allows us to really interact with our stakeholders and get their input.”
The owner of the 40-MW White Pine coal-fired power plant in Michigan’s Upper Peninsula blasted MISO after receiving a 90-day notice that the grid operator will terminate its $7.3 million annual system support resource agreement with the 60-year-old plant on Nov. 26.
White Pine Electric Power, a subsidiary of Traxys North America, said the decision jeopardizes reliability until 2020, when 170 MW of new natural gas-fired plants will come online. “This is a short-sighted decision by MISO that they claim is about utility rates,” said White Pine board Chairman Brent Zettl.
The utility claims that the study MISO used to make its decision did not properly evaluate emergency scenarios, arguing that the plant provides a failsafe against unplanned outages.
William E. Webster Jr., former executive vice president for industry strategy at the Institute of Nuclear Power Operations, joined Duke Energy’s board of directors effective Sept. 1.
Webster retired from INPO on June 30, ending a career there that began in 1982. While at INPO, he also served in “on‑loan” leadership positions with FPL Group and Arizona Public Service’s Palo Verde Nuclear Generating Station.
He received his senior reactor operator certification at Duke’s Brunswick nuclear plant and has a bachelor’s degree in civil engineering from Villanova University.
The 200-MW Odell Wind Farm began generating power in southwestern Minnesota last week under a 20-year power purchase agreement with Xcel Energy, its fourth wind facility in the Upper Midwest.
Owned and operated by Canadian company Algonquin Power & Utilities, Odell consists of more than 100 turbines erected in four counties.
Xcel gets 14% of its power from wind sources in the Upper Midwest and predicts the share will rise to 22% in 2020. Xcel’s ultimate goal is 42% from wind.
NYISO has named former energy executive Roger B. Kelley to its Board of Directors, effective this month. He replaces Vikki L. Pryor, whose term expired in April.
Kelley has more than 40 years of experience in the electric generation and transmission business. He previously served as CEO of Peregrine Midstream Partners in Houston. He was also CEO of Midland Cogeneration Venture in Midland, Mich.; CEO of Fortistar Renewables, based in White Plains, N.Y.; and CEO of the New York Power Authority.
“Roger has extensive experience in the energy industry, including as president and CEO of the New York Power Authority,” said Michael Bemis, NYISO’s board chair. “We appreciate his willingness to serve as a director. I’m confident we will benefit from his judgment and counsel.”
Prior to agreeing to a merger with Tesla, SolarCity considered selling its Buffalo solar panel manufacturing plant, which is scheduled for completion next June with $750 million in state assistance, according to a filing with the U.S. Securities and Exchange Commission.
SolarCity eventually decided a sale of the plant, a centerpiece of Gov. Andrew Cuomo’s Buffalo Billion economic development program, would not provide an adequate return for company shareholders. But the filing reveals how strapped for cash SolarCity is, even as it considered being acquired for $2.4 billion. The company’s operations rely heavily on a business model that allows customers to install rooftop solar with no upfront costs, forcing it to constantly raise money from investors.
The filing also reveals at least three other firms declined to acquire SolarCity before it accepted the offer from Tesla, which is facing a cash crunch itself. The company will have to pay $422 million to bond holders in the third quarter. Tesla’s debt-to-equity ratio was 145.5% as of June 30; SolarCity’s was 375.6%.
Development Partners, which is building a $500 million, 700-MW natural gas plant in northern Indiana, has asked MISO to allow it to double the size and the cost of the plant.
The White Plains, N.Y., company wants permission to add two more turbines to the St. Joseph Energy Center near the Michigan border. The first phase of the project is scheduled to be completed in 2018.
After Development Partners gets interconnection approval from MISO, which it hopes to earn by the end of the year, the developer would work with local officials to approve a site plan.
Enbridge Energy Partners, which recently invested $1.5 billion into a rival oil-pipeline project, has put its proposed Sandpiper Pipeline in Minnesota on hold, saying current demand for crude oil no longer supports the need for the project.
Sandpiper, which was initiated three years ago, aimed to carry up to 225,000 barrels of oil from North Dakota through Minnesota and then on to Superior, Wis. The proposal faced heated opposition from Native American tribes and environmental groups who objected to the proposed path, which would have crossed numerous lakes and rivers.
Enbridge stopped short of saying the project was dead, but it did say the five-year projection of production in North Dakota’s Bakken region doesn’t forecast the need for more pipeline capacity. The decision comes just after its recent $1.5 billion investment in the Bakken pipeline system, which includes the Dakota Access project.
Portland General Electric is exploring the possibility of converting its coal-fired Boardman power plant in eastern Oregon to biomass.
The utility plans to run the 550-MW facility on woody biomass for one full day this year as an experiment, following a successful test last year using a 10-to-1 mixture of coal and biomass. The process will entail pulverizing wood debris into the substance before feeding it into the plant’s boiler.
Boardman is slated for closure in 2020, but the use of biomass could extend the life of the plant. Success of the project will hinge on plant conversion costs and securing a steady supply of fuel.
Southern Co., Kinder Morgan Close Deal on Pipeline System
Southern Co. has acquired 50% of Kinder Morgan’s Southern Natural Gas pipeline system, the companies announced. The 7,000-mile system runs from wells in Texas, Louisiana, Mississippi and Alabama to markets in the southeast. Terms of the acquisition were not announced. Kinder Morgan will continue to operate the pipeline system.
Southern CEO Thomas A. Fanning hinted at other deals possibly in the works. “With our new ownership stake in Southern Natural Gas, we look forward to working with Kinder Morgan to explore future opportunities to deliver natural gas to customers,” he said.
Talen Energy withdrew its request for an operating license from the Nuclear Regulatory Commission for the proposed Bell Bend nuclear station in Berwick, Pa., saying that the reactor design company’s decision to suspend its certification process left it no choice.
The Allentown, Pa., company said that it had posted a $122 million loss associated with the project when it released its second-quarter results and that it would stop attempts to get a license for the plant. The reactor design company, Areva, asked NRC in 2015 to stop its design certification process. A Talen spokesman said seeking another design company wasn’t feasible.
Talen said the decision was not related to is pending merger with Riverstone Holdings.
General Electric is joining an energy research program at the Massachusetts Institute of Technology that aims to cut carbon emissions.
GE is contributing $7.5 million to the MIT Energy Initiative for research, particularly in solar power, energy storage, advanced power grids and carbon sequestration, company officials said.
“This partnership really is about advancing the state of the art in low-carbon technologies,” said Steve Bolze, chief executive of the $29 billion GE Power division.
EnerNOC has been awarded a multi-million-dollar contract by Consolidated Edison for the Brooklyn-Queens Demand Management program, part of New York’s Reforming the Energy Vision initiative. The program’s aim is to reduce demand in certain areas of New York City, delaying or eliminating the need for a $1.2 billion substation.
The BQDM project has been described as the largest modern “non-wires” alternative program in the U.S. relying on the use of energy efficiency and demand-side management in lieu of traditional generation and distribution infrastructure.
Duke Energy and 33 solar developers reached an agreement that will allow many solar generation projects to go forward and interconnect with the utility’s grid.
Earlier this summer, Duke announced that so many solar projects are seeking interconnection with their grid that it might cause problems and was going to require each new project to undergo a technical review. The new agreement allows the projects to connect while preserving Duke’s right to disconnect if problems arise. There are 3,300 MW of solar projects in various stages of planning and construction in North Carolina.
“In some areas of our system, we’re reaching a saturation point with solar, and in some places it is ill-placed,” a Duke spokesman said. The intermittent nature of the generation could cause problems with some of the lower-voltage circuits, the company says.
Riverside County officials are advancing a plan to create an alternative retail electricity supplier that would supplant Southern California Edison in unincorporated areas of the county. The officials say that the community choice aggregator, which would purchase power directly from producers, would allow county residents to lower their costs and increase reliance on renewables.
The county plans to engage a third-party consultant to develop and run the program, which would require approval from the state’s Public Utilities Commission. Residents and businesses will be automatically enrolled in the program but could opt out and continue using SCE if they choose. Incorporated communities would have the option to join up after the program is implemented.
Community choice aggregators are authorized under a 2002 state law. Though only four have been formed, renewable advocates are promoting them as a mechanism to allow communities to have more control over the source of their electrical power.
Regulators have approved a 2% rate hike for Duke Energy customers to help the company pay for its beleaguered Edwardsport coal-gasification plant.
Under a settlement, Duke will pay $87.5 million of deferred operating costs dating from when the plant went into service in 2013. The plant’s price tag has climbed to $3.5 billion from its original estimate of $1.9 billion.
The settlement was supported by the state Office of Utility Consumer Counselor, along with industrial customers, environmentalists and consumer advocates. It would result in an additional $1.83/month for the typical residential customer. The company has absorbed about $900 million in construction overruns on the plant.
IUB Denies Permanent Stay to Dakota Access Construction
The Utilities Board unanimously denied landowners’ request for a permanent stay of construction of the Dakota Access pipeline pending a court ruling on whether eminent domain can be used to access their properties.
The board heard about 45 minutes of testimony before deliberating in closed session. When it returned to open session, Chair Geri Huser said the board found that the potential harm of a permanent stay outweighed the potential benefits, as it found little chance of success in the petitioners’ complaint before the Polk County District Court.
The landowners had requested an emergency session of the board to hear their request. But Huser said “any apparent emergency that may exist was created by the petitioners’ own actions and their own decisions.” The board did extend a temporary stay currently in place until 9 a.m. Monday to give the landowners time to file an appeal in court. Commissioner Nick Wagner voted against the extension.
The Public Service Commission has scheduled two public hearings to discuss PEPCO’s request to increase its electric distribution rate by $104 million for 560,000 customers in Prince George’s and Montgomery counties. A typical residential customer would pay $13 more a month under the proposed rate. (Case No. 9418)
Hearings will be Sept. 6 at the Montgomery County Executive Building in Rockville, Md., and Sept. 8 at Prince George’s Community College in Largo, Md.
NRG Energy will pay $1 million to settle a lawsuit alleging two coal-fired plants illegally released high levels of nitrogen in wastewater.
The state filed suit in 2013 alleging NRG’s Chalk Point and Dickerson stations discharged illegal amounts of nitrogen and phosphorus into the Potomac and Patuxent rivers. The chemicals have been blamed for feeding algae that suck oxygen out of the Chesapeake Bay, creating dead zones for fish, crabs and vegetation.
In some years, the state said, the Chalk Point plant released 20 times as much nitrogen as its permit allowed. NRG will also pay $1 million to fund environmental restoration projects and invest $10 million to upgrade the wastewater systems at the two plants.
Public Service Commission Chair Sally Talberg told the Senate Energy Committee last week that the state would go “dark” in 10 years if policymakers did not address an impending electricity shortage.
The committee discussed the PSC’s recent five-year outlook, which predicts reliability challenges during peak demand in the Lower Peninsula, although it forecasts the state will meet minimum reliability standards through imports for the foreseeable future.
State Sen. Mike Shirkey (R) downplayed the report, telling reporters it could be “ripe with people cherry picking pieces of information and then reframing them to advance their narrative.”
Residents Asked to Conserve Water to Help Colstrip Plant
Williams
Colstrip residents were asked to limit their water use so the nearby power plant can continue to safely operate. The notice came at the request of Talen Energy, which operates the 2,100-MW plant.
Colstrip Mayor John Williams asked the city’s 2,300 residents to minimize their use of water for sprinkling and irrigation through the end of August. Williams said low water levels and high temperatures have caused problems with Talen’s water intake system on the Yellowstone River.
Lincoln Electric Plans to Show Off New Solar Farm in September
Lincoln Electric System will dedicate the state’s first commercial solar energy park next month and commemorate the event with tours for customers who helped finance the project.
The utility’s SunShares program allows about 1,200 enrolled customers to pay extra on their monthly bills to support solar energy.
The 5-MW, $8.9 million community solar project is owned by developer Enerparc. LES has a 20-year contract to buy power from the company. Construction began in March, and it went online in late June, producing enough electricity to power about 900 homes.
The Division of Rate Counsel said it will argue against FirstEnergy’s plan to spin off Jersey Central Power & Light’s transmission facilities into a new company to be called Mid-Atlantic Interstate Transmission. The assets include about 2,500 miles of transmission lines and towers.
“We believe that ratepayers are getting the short end of the stick because MAIT is getting these at a very, very favorable price,” said Stefanie Brand, the division’s director.
The Public Regulation Commission is being criticized for its decision last week to reopen hearings for Public Service Company of New Mexico (PNM)’s proposed rate increase. Commissioners said that the case could be extended through December if the utility decides to submit more evidence showing that its energy investments are prudent.
Reopening the proceedings, which began in April, would undermine a determination earlier this month by hearing officer Carolyn Glick, who recommended a 6% increase rather than the 15.8% increase PNM is seeking to cover some $123.5 million in costs. The company has threatened to go to court if the lower increase is approved.
Intervenors said Aug. 25 that the PRC’s decision gives the company too much leeway. If the case is reopened, it would be PNM’s third opportunity this year to provide proof that its investments are fair for ratepayers.
Entergy Would Get Termination Fee if FitzPatrick Sale Fizzles
The New York Power Authority will pay Entergy a $35 million termination fee if the sale of the FitzPatrick nuclear plant to Exelon falls through.
According to spokesman Steven Gosset, NYPA established a $35 million letter of credit that will pay Entergy if the PSC does not approve the sale to Exelon by Nov. 18. Entergy also would get the money if the New York State Energy Research and Development Authority fails to sign a contract by Nov. 18 that guarantees nuclear subsidies for FitzPatrick.
Both of those scenarios, and others that would trigger the fee, are unlikely, said Gosset, who declined to provide a copy of the letter. Entergy also declined to comment on the agreement.
University, Energy Companies Partner in Carbon-Capture Efforts
A diverse group of energy businesses are partnering with the University of North Dakota to develop carbon capture and sequestration technology.
ALLETE Clean Energy, Minnkota Power Cooperative and BNI Energy signed a memorandum of understanding with the university’s Energy and Environmental Research Center to submit a bid to the U.S. Department of Energy for a proposal they call Project Tundra, which aims to devise a way to reduce carbon dioxide emissions from existing coal-fired plants.
U.S. Sen. John Hoeven (R) said he had worked to secure $30 million to assist in the development of commercially viable and retrofittable CCS technology. The bill has passed in the Senate and now awaits House approval, Hoeven said.
AEP Asks PUCO for Distribution Hike to Counter Residential Solar
American Electric Power has asked the Public Utilities Commission for permission to increase the fixed monthly distribution charges for all of its customers to make up for the number of residential customers who are installing rooftop solar and energy efficient technology.
AEP Ohio says it has seen the number of solar net metering customers rise from 286 in 2011 to 983. AEP is asking to increase the average customer charge from $8.40 to $18.40.
“This increase in net metering customers is currently resulting in a shift of the recovery of fixed costs from net metering customers to non-net metering customers,” company spokeswoman Terri Flora said. The hike wouldn’t result in any more revenue for the company, Flora said, but opponents say the increase would discourage installing solar distributed resources.
Regulators Hear Arguments On PSO’s $130M Rate Case
The Corporation Commission last week heard arguments in the long delayed matter over Public Service Company of Oklahoma (PSO)’s requested $130 million electric rate increase. Consumer advocates argue that existing rates should be cut by up to $7 million, and an administrative law judge recommended a nominal rate increase of $676,000.
PSO filed the rate case in July 2015, and the company implemented an interim $75 million rate increase in January after it did not receive a final decision within the required six-month time period. The interim rate increase is subject to refund if the commission finds the utility wasn’t entitled to the extra revenue.
The company said the rate increase was needed to recover $453 million in system investments from February 2014 to July 2015. The utility also spent another $215 million this year on plant upgrades to meet federal environmental regulations.
About 300 people attended a public meeting held by the Public Utilities Commission to gather comments on a proposed wind farm north of Avon.
The 201-MW wind farm, proposed by developer Prevailing Winds, would have 100 turbines generating up to 860 GWh annually. Company representatives gave a presentation about the project and argued for the need for more wind power.
The project has generated opposition from some neighboring landowners. Some see the turbines as “eyesores,” while the others said they were concerned about potential health effects.
Environmental advocates at a Sunset Advisory Commission hearing on the Railroad Commission urged state lawmakers to require coal companies to set aside resources to cover the cost of cleaning up mines. Coal companies are currently allowed to self-bond, a process that could leave residents on the hook for more than $250 million in environmental cleanup costs if the companies renege on their obligations.
The state currently allows four coal mining companies to self-insure the cost of cleaning up seven strip mine operations. With the coal industry’s financial challenges, experts say taxpayers are at risk.
The Sunset Commission, which assesses the continued need for state agencies, held the hearing to get feedback on a scathing report published in April by its staff advisory committee on the inefficiencies and inadequacies of the Railroad Commission, which, despite its name, regulates energy extraction industries in the state.
FirstEnergy asked state regulators to approve a $6.9 million rate surcharge for MonPower and Potomac Edison customers to pay for upgrades at two coal-fired plants.
The requests were made possible by a coal-industry supported bill approved five months ago, which allowed utilities to pass through costs for upgrading their coal-fired plants without having to go through a formal rate proceeding. At the time the bill was introduced, FirstEnergy said it didn’t have any plans to use the provision.
The total cost of the upgrades at the Harrison and Fort Martin plants will be more than $76 million, according to company filings. The surcharges, if approved, will increase a typical residential customer’s rates about $6.60 per year.
SPP’s Market Monitoring Unit filed its 2015 State of the Market report with FERC on Friday, saying the Integrated Marketplace’s second year of operation showed “significant maturing,” illustrated by high participation, “lower levels of make-whole payments and mitigation compared to other markets, and a modest level of scarcity pricing.”
The MMU’s report noted the market was affected by low natural gas prices, increasing wind generation and an expanding footprint. The RTO’s territory grew about 10% in both generation and load with the October addition of the Integrated System, which covers the Dakotas and parts of several other Upper Midwestern states.
According to the report, average monthly natural gas prices were “generally flat” at about $2.50/MMBtu through September, declining to below $2/MMBtu in December. The energy market’s average all-in price was $23.48/MWh.
The MMU said the amount of wind energy continues to increase and represented almost 20% of total SPP generation in November and December. Although congestion declined systemwide, it increased in areas with wind generation.
Coal generation, on the other hand, has declined from a historical average of 60 to 65% to an average of 55% in 2015. In November, coal represented only 45% of SPP’s total generation, according to the report.
SPP ended the year with 12,398 MW of installed wind capacity, a 44% increase from the 8,606 MW in 2014. The MMU said actual generation resulting from new capacity does not show up in the market for several months after registration, and the full impact of the nearly 4,000 MW in new wind capacity will not be felt until 2016.
“Initial results from 2016 indicate that at times generation is approaching 50% of total load,” the MMU said, a “substantial increase” from the 34% average in 2015. SPP’s current wind penetration record is 48.32%, set April 5.
The MMU said the market saw a 156-MW increase in installed generation capacity to 67,251 MW. Along with a slightly lower system peak load compared to 2014, that resulted in a small increase in the market resource margin, from 48% in 2014 to 49%.
“Given the large resource margin and the frequency with which the LMP represents inexpensive generation,” the report said, “prices generally did not rise to levels high enough to support investment in new generating capacity.”
Fitch Affirms SPP’s Long-Term Debt at A, Gives Stable Rating
Fitch Ratings on Friday affirmed SPP’s long-term issuer default rating (IDR) at “A” and gave the RTO a “stable” rating outlook. Fitch also affirmed SPP’s short-term IDR at “F1” and noted the actions affected approximately $268 million in debt.
The agency cited as positives the $66 million in debt maturities being repaid with available cash through 2018 and the $71 million in capital expenditures through 2018, a 19% decrease compared to the prior three years.
Fitch also noted SPP’s projection that the addition of the Integrated System will produce $334.1 million in savings over 10 years.
It said the RTO’s voluntary membership “is a modest credit concern” but that the departure risk “is mitigated by the requirement that the exiting member pay a fee equal to its share of SPP’s outstanding debt and other committed expenses as an ‘exit charge.’”
SPP RE Sets Week of Meetings in Oklahoma City
The SPP Regional Entity has room for either in-person or webinar attendance for its fall workshop Sept. 20-21 in Oklahoma City. The workshop is sandwiched between a Regional Compliance Working Group meeting Sept. 19 and an RTO compliance forum Sept. 21-22. All meetings will be held at the Skirvin Hilton Hotel.
Dominion Virginia Power has applied with the Virginia State Corporation Commission to replace the existing 500-kV Carson-Rogers Road Line in Greensville County. The project, if approved, would cost about $52.9 million and be completed in December 2018.
The company says the project will ensure it meets mandatory NERC and PJM reliability standards. The existing line went into service in 1972 and is nearing the end of its service life.
Westar, Great Plains Shareholders To Vote on Merger in September
Great Plains Energy and Westar Energy shareholders will vote on Great Plains’ proposed $12.2 billion acquisition of Westar in separate but concurrent special shareholder meetings Sept. 26. The deal would pay Westar shareholders $51/share plus $9/share in Great Plains stock.
Westar will hold its meeting at the Kansas Expocentre in Topeka, while Great Plains will host shareholders at its Kansas City office. Shareholders as of the close of business on Aug. 22 are entitled to vote. The companies expect most individual shareholders to mail their votes.
The two companies filed a proxy statement Aug. 25 detailing the transaction, which must be approved by stockholders and multiple regulatory agencies. They expect the deal to close next spring.
PSO Names 40-Year Veteran As VP of Generation Group
Public Service Company of Oklahoma last week named Tommy Slater as vice president of the company’s generating assets. Slater, currently a plant manager at sister company Southwestern Electric Power Co.’s Welsh Plant in Texas, replaces Gary Knight, who is retiring after 35 years with PSO.
Prior to his 2010 appointment as manager at Welsh, Slater worked as a start-up engineer, plant shift supervisor and manager for SWEPCO’s regional engineering organization.
Slater has a bachelor’s degree in mechanical engineering from the University of Texas at Arlington and is a registered professional engineer in Texas.
A Delaware bankruptcy judge approved the Chapter 11 plan of Luminant and TXU Energy, the two main operating businesses of Energy Future Holdings.
“I believe at the end of the day, this is the best possible deal,” Judge Christopher Sontchi said Friday. The plan will launch a new company containing Luminant and TXU Energy. It will be taken over by senior lenders, including affiliates of Apollo Global Management, Brookfield Asset Management and Oaktree Capital Management.
Phase two of EFH’s bankruptcy, valued at $42 billion, involves the sale of the company’s 80% stake in Oncor to NextEra Energy.
The U.S. Bankruptcy Court for the District of Delaware has approved a reorganization plan that will take Energy Future Holdings’ competitive businesses out of Chapter 11 after two years.
In a statement posted on its website Friday, Dallas-based EFH said the bankruptcy judge approved Texas Competitive Energy Holdings’ tax-free spinoff of generator Luminant, electric retailer TXU Energy and supporting business services. The Wall Street Journal reported that the companies will be taken over by senior lenders, including affiliates of Apollo Global Management, Brookfield Asset Management and Oaktree Capital Management.
Luminant Sign outside their Lamar Plant Source: Energy Future Holdings
EFH said the “Reorganized TCEH,” as it will be known in the short term, has already received “a majority of the key regulatory approvals required for emergence,” in addition to the bankruptcy court’s approval. EFH expects a final approval, related to Luminant’s mining operations, from the Railroad Commission of Texas in September.
U.S. Bankruptcy Judge Christopher Sontchi said the plan “was the best possible deal” for EFH to emerge from bankruptcy.
The bankruptcy court’s approval doesn’t apply to EFH’s regulated transmission and distribution provider, Oncor. NextEra Energy has reached an agreement to buy for $18.4 billion the 80% share of Oncor currently owned by EFH and Energy Future Intermediate Holdings, another of EFH’s several holding companies. (See NextEra Reaches Deal for Oncor.)
Map of Luminant Plants Source: Luminant
A confirmation hearing on the Oncor assets’ emergence from bankruptcy is scheduled to begin Dec. 1.
EFH, then known as TXU Corp., was acquired in 2007 by private equity firms KKR & Co., TPG Capital LP and Goldman Sachs Capital Partners through a $45 billion leveraged buyout. Low gas prices have bedeviled EFH ever since, forcing the holding company to file for bankruptcy protection in April 2014.
Lawyers representing EPA last week argued that multimillion-dollar boiler upgrades in 2007 and 2010 at Ameren Missouri’s Rush Island facilities south of St. Louis should have required a permit and review process under the Clean Air Act.
In the 1990s, Ameren decided to switch to a new, ultra-low-sulfur coal rather than install new controls. This resulted in operational problems at the plant, leading the company to make $72 million worth of upgrades, including boiler modifications and a new turbine. It also led, EPA argued, to increased electricity output and, thus, increased emissions.
James W. Beers Jr., of the Justice Department’s Environment and Natural Resources Division, argued that the upgrades are new sources of pollution and should be subjected to more rigid emissions limits. He said that Ameren should install new sulfur dioxide controls at the plants. Ameren said the improvements were part of routine maintenance and should not fall under Clean Air Act standards. The company also argued that EPA cannot prove that the rise in emissions resulted from the upgrades and not from increased electricity demand.
Federal regulators have cited R.E. Ginna nuclear plant owner Exelon for a safety violation because the station’s emergency plan contained a sentence that misused less-than symbols.
If a serious accident had occurred, the written emergency management decision flowchart could have led control room operators to mistakenly call for a mass evacuation, according to the Nuclear Regulatory Commission. The mistake proved harmless, as there was no serious accident during the two-and-a-half years the error existed in the tree-like graph, intended to support decision-making during critical incidents.
The mistake was discovered by an Exelon supervisor this spring as plant personnel prepared for an emergency drill. The commission classified the error as a low-to-moderate level violation.
FAA Stands by its Greenlight For Proposed Wind Farm
The Federal Aviation Administration is standing by its previous determination that the proposed Chapman Ranch wind farm in South Texas would “not have an adverse effect on the safe and efficient use of the navigable airspace” primarily used by the U.S. Navy for training pilots out of Kingsville and Corpus Christi.
The administration’s decision, along with an agreement between the Navy and developer Apex Clean Energy, still leaves unresolved concerns that the wind farm may make the area less attractive to the military for training. The agreement allows the Navy to shut down the wind farm’s operation any time it interferes with its operations, according to John Kelley, who represents the Chapman family.
The Corpus Christi City Council, which annexed lands to assert some control over the facility’s development, responded to FAA’s decision by stripping $14 million from next year’s budget for capital improvement projects for the newly annexed land.
The Tennessee Valley Authority has filed a request with the Nuclear Regulatory Commission to allow power uprates at its Browns Ferry Nuclear Plant.
The Blue Ridge Environmental Defense League opposes the request, saying that TVA’s calculation “under-predicts the reaction of zirconium and steam that would occur in a loss-of-coolant accident.”
“NRC should seek to reduce, not increase, the risk of loss of coolant that will melt the fuel rods leading to meltdown and released radiation,” said Gary Morgan of the group’s Scottsboro-based chapter.
Renewable Production Beat Records Each Month of 2016
Renewable energy production set new records each month of 2016, according to the Energy Information Administration.
The measures run through June and include utility-scale wind, solar, hydro, geothermal and biomass plants larger than 1 MW. The records were attained despite low numbers for hydro because of the drought in the West. And while most renewables have been increasing their share, hydro’s share has remained unchanged for the past 20 years.
The Federal Trade Commission approved Tesla Motors acquisition of the home solar installation company SolarCity, a move the car manufacturing company said would further its goal of providing a one-stop shop for solar panels, home battery storage and electric cars.
The $2.6 billion transaction, announced earlier this month, still needs other regulatory approvals, but SolarCity said it hopes the deal closes by the end of the year.
A study in Environmental Health Perspectives drew a connection between living near shale gas wells and an increased rate of migraines, fatigue and sinus problems. The report, based on 7,785 randomly selected patients of a Pennsylvania health system, showed that those living closest to fracking sites were 49% to 95% more likely to show signs of chronic sinusitis, migraines and fatigue.
The senior author, Dr. Brian S. Schwartz, admitted there could be other variables and said the study was observational, not one that proved cause and effect.
However, he said, “there have now been seven or eight studies with different designs and in different populations, and while none is perfect, there is now a growing body of evidence that this industry is associated with impacts on health that are biologically plausible. Do we know the exact mechanism? No. That requires further study.”
Environmentalists are challenging a Bureau of Land Management plan to lease more than 19,000 acres of federal land in Montana for oil and gas exploration.
WildEarth Guardians says BLM officials have failed to consider the climate damage done by fossil fuel development. The Center for Biological Diversity and the Theodore Roosevelt Conservation Partnership have also filed protests on the proposed lease, which is slated for auction Oct. 18 in Billings.
The group has been aggressively challenging BLM leases in several Western states, including Wyoming, Colorado and Utah, on grounds similar to those cited by the group in Montana. BLM has leased more than 800,000 acres of federal land for oil and gas development last year alone.
The 200-MW Odell Wind Farm began generating power in southwestern Minnesota last week under a 20-year power purchase agreement with Xcel Energy, its fourth wind facility in the Upper Midwest.
Riverside County officials are advancing a plan to create an alternative retail electricity supplier that would supplant Southern California Edison in unincorporated areas of the county. The officials say that the community choice aggregator, which would purchase power directly from producers, would allow county residents to lower their costs and increase reliance on renewables.
Regulators have approved a 2% rate hike for Duke Energy customers to help the company pay for its beleaguered Edwardsport coal-gasification plant.
The Utilities Board unanimously denied landowners’ request for a permanent stay of construction of the Dakota Access pipeline pending a court ruling on whether eminent domain can be used to access their properties.
The Public Service Commission has scheduled two public hearings to discuss PEPCO’s request to increase its electric distribution rate by $104 million for 560,000 customers in Prince George’s and Montgomery counties. A typical residential customer would pay $13 more a month under the proposed rate. (Case No. 
Lincoln Electric System will dedicate the state’s first commercial solar energy park next month and commemorate the event with tours for customers who helped finance the project.
The Division of Rate Counsel said it will argue against FirstEnergy’s plan to spin off Jersey Central Power & Light’s transmission facilities into a new company to be called Mid-Atlantic Interstate Transmission. The assets include about 2,500 miles of transmission lines and towers.
The Public Regulation Commission is being criticized for its decision last week to reopen hearings for Public Service Company of New Mexico (PNM)’s proposed rate increase. Commissioners said that the case could be extended through December if the utility decides to submit more evidence showing that its energy investments are prudent.
The New York Power Authority will pay Entergy a $35 million termination fee if the sale of the FitzPatrick nuclear plant to Exelon falls through.
A diverse group of energy businesses are partnering with the University of North Dakota to develop carbon capture and sequestration technology.
American Electric Power has asked the Public Utilities Commission for permission to increase the fixed monthly distribution charges for all of its customers to make up for the number of residential customers who are installing rooftop solar and energy efficient technology.
About 300 people attended a public meeting held by the Public Utilities Commission to gather comments on a proposed wind farm north of Avon.
Environmental advocates at a Sunset Advisory Commission hearing on the Railroad Commission urged state lawmakers to require coal companies to set aside resources to cover the cost of cleaning up mines. Coal companies are currently allowed to self-bond, a process that could leave residents on the hook for more than $250 million in environmental cleanup costs if the companies renege on their obligations.
FirstEnergy asked state regulators to approve a $6.9 million rate surcharge for MonPower and Potomac Edison customers to pay for upgrades at two coal-fired plants.
One ratepayer said she was charged eight extra times for the same $135 bill, and $1,215 was automatically withdrawn from her account.
Dominion Virginia Power has applied with the Virginia State Corporation Commission to replace the existing 500-kV Carson-Rogers Road Line in Greensville County. The project, if approved, would cost about $52.9 million and be completed in December 2018.
Great Plains Energy and Westar Energy shareholders will vote on Great Plains’ proposed $12.2 billion acquisition of Westar in separate but concurrent special shareholder meetings Sept. 26. The deal would pay Westar shareholders $51/share plus $9/share in Great Plains stock.
Public Service Company of Oklahoma last week named Tommy Slater as vice president of the company’s generating assets. Slater, currently a plant manager at sister company Southwestern Electric Power Co.’s Welsh Plant in Texas, replaces Gary Knight, who is retiring after 35 years with PSO.
A Delaware bankruptcy judge approved the Chapter 11 plan of Luminant and TXU Energy, the two main operating businesses of Energy Future Holdings.
In the 1990s, Ameren decided to switch to a new, ultra-low-sulfur coal rather than install new controls. This resulted in operational problems at the plant, leading the company to make $72 million worth of upgrades, including boiler modifications and a new turbine. It also led, EPA argued, to increased electricity output and, thus, increased emissions.
Federal regulators have cited R.E. Ginna nuclear plant owner Exelon for a safety violation because the station’s emergency plan contained a sentence that misused less-than symbols.
The Federal Aviation Administration is standing by its previous determination that the proposed Chapman Ranch wind farm in South Texas would “not have an adverse effect on the safe and efficient use of the navigable airspace” primarily used by the U.S. Navy for training pilots out of Kingsville and Corpus Christi.
The Tennessee Valley Authority has filed a request with the Nuclear Regulatory Commission to allow power uprates at its Browns Ferry Nuclear Plant.
Environmentalists are challenging a Bureau of Land Management plan to lease more than 19,000 acres of federal land in Montana for oil and gas exploration.