The landmark climate deal reached in Paris on Saturday will have wide-ranging impacts on utilities and other industries, analysts say. More than 190 countries pledged to reduce their emissions of carbon and other heat-trapping gases following two weeks of negotiations.
Investment funds will move their portfolios from coal and oil to renewables — reflecting utilities’ shifting generation mix — while inventors will seek breakthroughs in energy storage and carbon capture technologies, and automakers will have to expand production of electric cars.
Business leaders have long complained that the lack of a clear political message on global warming was hamstringing their investment decisions.
“We have an opportunity to build a new economy, and business is poised to help make it happen,” said Richard Branson, CEO of the Virgin Group. “The ‘Paris effect’ will ensure the economy of the future is driven by clean energy.”
“It’s very hard to go backward from something like this,” agreed Nancy Pfund, managing partner of DBL Partners, a venture capital firm. “People are boarding this train, and it’s time to hop on if you want to have a thriving, 21st-century economy.”
The success of the Paris meeting was in stark contrast to the failure of the 2009 talks in Copenhagen. But the commitments made last week won’t be enough to meet the agreement’s goal of keeping global warming “well below” 2 degrees Celsius (3.6 degrees Fahrenheit).
NRC Grants 20-Year Extension to FirstEnergy’s Davis-Besse
Despite its own characterization of the plant’s history as troubled, the Nuclear Regulatory Commission issued a 20-year license extension to FirstEnergy’s Davis-Besse nuclear plant in Ohio. NRC reviewed the plant’s operational record for five years, substantially longer than most license-extension reviews.
“We had a couple of issues that took a little longer to understand the full ramifications,” said Sam Belcher, FirstEnergy’s chief nuclear officer.
Davis-Besse experienced a partial loss of coolant in 1985, cracks in its containment building and serious corrosion of the plant’s reactor head in 2002, contributing to its becoming a target of anti-nuclear activists such as Terry Lodge, who called Davis-Besse “a contrivance of regulatory neglect and corporate welfare.”
The Nuclear Regulatory Commission has told Entergy it can continue to operate the Indian Point nuclear power plant’s Unit 3 under its existing license while its license renewal review continues.
Unit 3’s 40-year license would have expired at midnight on Saturday had Entergy not applied for a license renewal eight years ago, the company said. Entergy can continue to operate the plant in Buchanan, N.Y., under the federal government’s “timely renewal” provision and until NRC makes a final determination on the company’s license renewal request.
The other operating plant at Indian Point, Unit 2, received a similar approval from NRC in September 2013 prior to it entering the period beyond its initial 40-year license.
A faulty electrical breaker controlling a roof fan caused last week’s trip at Indian Point Unit 2, according to the Nuclear Regulatory Commission.
The commission said operators at the New York plant manually shut down the reactor Dec. 5 when the faulty breaker caused a drop in voltage to the mechanisms controlling about 10 of the reactor’s control rods. That caused those rods to drop into the reactor, slowing the reaction and trigging a shutdown.
FERC Tells Atlantic Coast Pipeline to Find Alternate Routes
FERC has told the developers of the $5.1 billion Atlantic Coast Pipeline project that they should look for alternative routes through the Monongahela and George Washington national forests on the West Virginia-Virginia border.
“To ensure that a complete and thorough evaluation of the ACP is presented in the draft environmental impact statement, we request that Atlantic identify and assess an alternative pipeline route across the national forests,” FERC said in a letter to Dominion Resources, the pipeline’s developer. FERC issued the directive after consulting with the U.S. Forest Service.
Dominion said it was not surprised by the FERC notice. “Our goal from the beginning has been to develop a route that meets the critical energy needs of our public utility customers with the least impact on people, the environment and historical and cultural resources — including locations where it crosses the working forests,” a Dominion spokesperson said. The 542-mile pipeline would deliver natural gas from Appalachian shale formations to North Carolina.
FERC Turns Down Request for Further Pipeline Study
FERC has turned down a request by landowners, local governments and environmental groups in Virginia and West Virginia to conduct a cumulative impact study of several proposed pipeline projects that would cross the region.
FERC said there was no precedent for such a study, which had been requested by the Blue Ridge Land Conservancy and other groups. Advocates say such a study could establish standards for multiple projects being cut through wilderness and farmlands.
“With the recent exponential increase in applications to FERC for new interstate pipelines to transport Marcellus Shale natural gas, FERC’s traditional project-by-project [National Environmental Policy Act] review has proven increasingly ineffective,” said the Water and Power Law Group.
FERC is being asked to issue a certificate of convenience to a proposed natural gas pipeline that would deliver shale gas from Ohio to customers in Michigan and Canada.
The NEXUS Gas Transmission project would run 255 miles through Ohio and terminate at the Dawn Hub in Ontario. Spectra Energy is working with other pipeline, gas storage and utility companies to develop the project.
“The NEXUS project will play a key role in helping the U.S. transition to cleaner sources for generating electricity — including new power plants fueled by natural gas — as coal plants are retired due to their age and environmental regulations,” said David Slater, DTE Energy’s president of gas storage and pipelines.
NRC Allows Entergy to Shrink Vermont Yankee Emergency Zone
The Nuclear Regulatory Commission has agreed to allow Entergy to cease to maintain the 10-mile radius emergency planning zone around its retired Vermont Yankee nuclear generating station. Entergy applied for permission to shrink the emergency zone to just the plant and its perimeter.
NRC spokesman Neil Sheehan said the company had proved it was able to contain any radiological release from the on-site spent fuel storage at the plant, which shut down at the end of 2014.
“Once the reactor is shut down, you no longer have to worry about the sudden kind of event where there’s a rupture of a steam line and there has to be immediate actions taken to protect the public,” Sheehan said. “They had to be able to demonstrate to us that they would be able to do whatever is necessary to make sure that that pool maintains its integrity so that that pool is protected.”
New York electricity customers would pay about $1.7 billion more annually over the next decade if the nuclear fleet operating on Lake Ontario shuts down, according to a new study by The Brattle Group.
The report, released Dec. 7, was prepared for three unions representing utility workers and building tradesmen in western New York.
The backdrop is the proposed shutdown of Entergy’s James A. FitzPatrick plant and the eventual closing of the R.E. Ginna plant, owned by Exelon, when a contract providing ratepayer subsidies runs out in 2017. (See Ginna Lifeline to End in 2017; Profits After ‘Unlikely’.)
Also included in the study is Exelon’s two-unit Nine Mile Point. The company has not indicated that the plant is in danger of closing but said its environmental attributes need to be recognized in the design of the wholesale market.
Nuclear supporters are trying to keep the plants running. Gov. Andrew Cuomo also has some ideas on how to keep the plants operating for the next 15 years for their air emissions benefits while New York transitions to more renewable and distributed energy in its power system. Details could be released at Cuomo’s State of the State address in January.
The three plants, with four reactors, have a combined generating capacity of 3,345 MW. They represent 7% of NYISO’s capacity but 15% of its electricity production.
The study said the plants lower wholesale electricity prices and mitigate the state’s ever-increasing reliance on natural gas for power generation. Without upstate nuclear, natural gas’ share of generation would rise from the current 40% to 54%, it said.
“This alternative generation mix would mean higher average electricity prices in New York, driven in part by energy market effects, but perhaps more importantly by the effect on NYISO capacity markets,” the study said. The power plants contribute approximately $3.16 billion to the state’s gross domestic product, account for nearly 25,000 full-time jobs (direct and indirect) and provide other benefits, such as avoiding 16 million tons of carbon dioxide emissions annually, according the report.
The plants also contribute $144 million in net state tax revenue annually, including more than $60 million in state and local property taxes.
The report was prepared for the International Brotherhood of Electrical Workers’ Utility Labor Council of New York, the Rochester Building & Construction Trades Council and the Central-Northern New York Building & Construction Trades Council.
AEP Ohio has reached a settlement with Public Utilities Commission of Ohio staff and others on an eight-year power purchase agreement, winning the support of the Sierra Club with a promise to double the state’s wind generation and nearly quintuple its solar capacity.
The settlement provides guaranteed income for the output of American Electric Power’s 2,671-MW ownership share of nine plants, as well as the company’s 423-MW contractual share of Ohio Valley Electric Corp.’s generating fleet, until May 2024, the company announced Monday.
AEP said the agreement, which still needs to be approved by PUCO, would raise a typical residential customer’s bill by 62 cents/month. But when coupled with its recently approved Electric Security Plan, rates will be $9/month less than rates a year ago, the company said.
AEP also predicted that the settlement agreement would result in savings to consumers of $721 million over its eight-year life.
Opponents say AEP’s projections assume an unlikely increase in natural gas costs in the later years. The Ohio Consumers’ Counsel (OCC) has predicted that the deal would cost consumers an extra $2 billion.
Minutes after AEP announced the settlement agreement, the OCC issued a release criticizing it.
“It’s a sad day for AEP’s consumers when, 16 years after the 1999 deregulation law, the government is being asked to impose charges on consumers for a bailout of deregulated power plants,” said Consumers’ Counsel Bruce Weston, who also opposed the FirstEnergy agreement. “Consumers should not be charged a penny more than the cost of power in the market.”
Many of the same companies and associations who are denouncing the settlement also criticized a similar agreement with FirstEnergy. Dynegy and Talen Energy have threatened to sue over the FirstEnergy deal, a warning repeated by Dynegy CEO Robert Flexon on Monday. “Dynegy will continue to fight for market-based policies that treat all forms of power generation equally through advocacy and litigation, if necessary, to prohibit these power purchase agreements from being enacted,” Flexon said. (See Merchant Generators Lead Opposition to FirstEnergy-Ohio Settlement.)The PJM Power Providers Group (P3) and the Electric Power Supply Association also blasted the agreement.
“It just doesn’t make sense that in the face of overwhelming testimony that competitive markets are working to push electricity rates to historically low levels in Ohio that the PUCO staff would yet again agree to a misguided proposal that will not improve reliability, will not reduce volatility, will force consumer to pay more for power and will drive innovation out of the state,” P3 President Glen Thomas said.
Environmental Support
Part of the AEP agreement is a commitment to retire or convert some of its coal-fired generators to natural gas. It also includes commitments to develop 900 MW of wind and solar projects, continued support for energy efficiency programs and up to $100 million in customer credits.
It was this combination of sweeteners that brought the Sierra Club into the fold. While the group was harsh in its criticism of the FirstEnergy deal — saying “PUCO’s staff decision to move forward with a backroom deal to bailout FirstEnergy’s aging power plants is insulting to Ohio utility customers” — it came out in support of the AEP plan.
“The proposed stipulation reflects a very difficult yet pragmatic discussion between AEP and Sierra Club,” senior campaign representative Daniel Sawmiller told The Columbus Dispatch. “While nobody will call this deal perfect, we’re proud of what it accomplishes toward reinvigorating Ohio’s clean energy economy and moving beyond coal.”
The group was swayed by AEP’s commitment to develop 500 MW of wind generation and 400 MW of solar within five years.
Ohio’s current installed wind capacity of 435 MW ranks 26th in the nation and contributes less than 1% of its in-state generation, according to the American Wind Energy Association. Another 259 MW is under construction.
The state has 106 MW of solar, ranking it 20th in the country, according to the Solar Energy Industries Association.
The nine AEP generating stations covered by the agreement are: Cardinal Unit 1 in Brilliant; Conesville Units 4-6 in Conesville; Stuart Units 1-4 in Aberdeen; and Zimmer Unit 1 in Moscow.
The environmental commitments to its plants cover converting Conesville Units 5 and 6 to co-fire natural gas by Dec. 31, 2017, and retiring, refueling or repowering Conesville Units 5 and 6 and Cardinal Unit 1 to only use natural gas by the end of 2029 and 2030.
In addition to PUCO staff and the Sierra Club, AEP said Ohio Partners for Affordable Energy, Ohio Energy Group, Ohio Hospital Association, Mid-Atlantic Renewable Energy Coalition and three competitive retail energy suppliers had agreed to sign or not oppose the settlement.
“This agreement addresses many of the concerns raised by a diverse group of parties including advocates for low-income customers, environmental organizations, industrial and commercial customers and competitive energy suppliers,” said Pablo Vegas, CEO of AEP Ohio.
The Ohio Environmental Council was among those not swayed. “We’re still very much opposed to this idea that consumers are being forced to pay for dirty energy,” Trish Demeter, the council’s managing director of energy and clean air programs, told The Columbus Dispatch.
In a dissenting opinion, authority member Michael Caron said the deal presents “too many unknowns” for regulators and the state’s ratepayers.
“Iberdrola is a multi-national conglomerate that is currently engaged in regulated and unregulated activities,” he wrote. “Consequently, parts of Iberdrola’s business may be more inherently risky than its regulated utilities. These risks outweigh the minimal public benefits provided in the settlement agreement.”
Iberdrola agreed to regulators’ demand for “ring fencing” of the company’s state operations from its other domestic and international holdings. But Caron said that the company’s responsibilities to its shareholders overall would undermine those protections for Connecticut ratepayers.
Caron also said Iberdrola’s previous ownership and sale of two Connecticut natural gas distribution companies showed a lack of commitment to the state.
In a statement, PURA Chairman Arthur H. House said the deal was in the public interest and overcame objections that officials had to the first proposal last summer.
“While their first proposal had many positive aspects, Iberdrola and UIL took to heart the message we sent in our preliminary ruling, measurably improving both the public benefit content of their proposal, and also making specific, measurable commitments that ensure the flow of benefits to utility ratepayers,” he wrote.
PURA Vice Chairman John Betkoski joined House in approving the acquisition.
The deal had won the endorsement of the state’s Consumer Counsel in September.
The deal must still be approved by UIL shareholders and Massachusetts regulators, who have jurisdiction over UIL’s natural gas distributor Berkshire Gas. The companies have asked that state’s Department of Public Utilities to rule by Dec. 18.
MISO and SPP last week concluded their first joint study process, saying the exercise was a valuable learning experience even though it failed to produce a single interregional project.
Meeting in Dallas on Dec. 2, the MISO-SPP Interregional Planning Stakeholder Advisory Committee (IPSAC) reviewed stakeholder feedback and its next steps after a year in which it considered and ultimately rejected 67 potential transmission upgrades. Under the current stakeholder-designed process, the two RTOs conduct a coordinated study that can last up to 18 months, followed by two separate regional analyses.
“The process itself did what [it] intended to do,” said David Kelley, SPP’s director of interregional relations. “Unfortunately, we couldn’t get any projects across the goal line. We have to find a way to get those done.”
Eric Thoms, MISO’s manager of planning coordination and strategy and Kelley’s counterpart on IPSAC, said the session was an opportunity to collaborate with stakeholders to improve the process “so we can set ourselves up for success next time.”
One of the sticking points is the so-called “triple hurdle,” created by necessary approvals from the joint-study process and each RTO’s board. SPP and MISO initially identified three congestion-relieving upgrades that would qualify as interregional projects, but SPP recommended moving forward with only one, an 11-mile, 138-kV rebuild between South Shreveport, La., and Wallace Lake.
MISO declined to pursue any of the three.
The RTO had said in October it may revisit its decision on the Shreveport-Wallace Lake project, but this week it said that it no longer intends to pursue the project. The project is described in MISO’s 2015 Transmission Expansion Plan, which will be submitted at Thursday’s MISO board meeting, but not listed among the approved projects in Appendix A.
Kip Fox, American Electric Power’s director of transmission strategy and grid development in the southwest, called the Louisiana project’s failure “very disheartening.” He said AEP will eventually rebuild the 11-mile segment as a reliability project for SPP, “even though it provides significant economic value to MISO South.”
“It’s the right thing to do for ratepayers along the seam, even though MISO will not provide financial support for the project in the MTEP15,” Fox said.
Among the suggestions stakeholders provided to IPSAC was the idea to include task teams with stakeholder representation in the process for “specific topics and detailed discussions.” However, the concept met with resistance over concerns it would create another level of approvals and diminish the IPSAC’s transparency efforts.
Stakeholders suggested eliminating the “triple hurdle” by creating an interregional evaluation process that does not require separate regional reviews. Another suggestion was a cyclical 18-month process that aligns with the RTOs’ transmission planning processes.
Both staffs agreed the interregional process had improved coordination between the two RTOs and increased the knowledge of each other’s regional processes and stakeholders.
Staff will update the MISO-SPP Coordinated System Plan to include a report on the regional reviews by year-end. The IPSAC will next meet in the first quarter of 2016, focusing on potential improvements to interregional procedures.
The region will once again rely on the RTO’s Winter Reliability Program to incentivize oil-fired power plants and natural gas generators that can access liquefied natural gas to procure sufficient backup fuel before winter begins. “The program has been a key factor in our ability to keep the lights on the last two winters,” said Vamsi Chadalavada, executive vice president and chief operating officer of ISO-NE.
More than 45% of the total generating capacity in New England — about 13,650 MW — uses natural gas as its primary fuel. Natural gas generated 44% of the region’s power in 2014, up from 15% in 2000.
The Department of Energy and Environmental Protection has issued the permits necessary for the 805-MW CPV Towantic Energy power plant to be built in Oxford.
DEEP officials said in a statement that the plant “will comply with some of the most stringent air pollution control requirements in the country and meet emissions limits designed to protect human health and the environment.” The CPV Towantic Energy power plant will operate primarily on natural gas, with the capability to use oil as a backup fuel.
The town of Middlebury and several property owners near the proposed site have challenged in court the Siting Council’s approval of the plant in May.
Palmco Power CT, a third-party electricity supplier for more than 3,500 residents, is being investigated by the Public Utilities Regulatory Authority for alleged deceptive marketing practices, according to Consumer Counsel Elin Swanson Katz. PURA is scheduled to hold public hearings on the allegations next week, and Katz is encouraging customers who feel they were subjected to Palmco’s alleged intimidating marketing tactics to come speak.
Palmco has come under fire for charging some of the highest electricity rates in the state. The company has also been investigated by New York and New Jersey authorities for alleged improper practices. Katz said one New York settlement resulted in Palmco and its partners agreeing to pay more than $2 million in refunds to consumers in that state, plus a $200,000 state penalty.
“In aggregate, Palmco customers in Connecticut paid over $412,000 more than the standard service rate … in September alone,” Katz said. Palmco recently stopped marketing to new customers in Connecticut after the state outlawed variable-rate contracts for residential customers.
Officials to Probe Steep Cost of Chicago Gas Mains
State regulators are taking a deeper look at the escalating price tag on a gas main replacement program for Peoples Gas, an Integrys Energy Group subsidiary based in Chicago.
The Commerce Commission will formally investigate whether Wisconsin Energy Corp. and Integrys conspired to conceal the escalating costs in order to win approval of their merger into WEC Energy Group. In November, Attorney General Lisa Madigan accused the companies of withholding details on the cost of the gas main replacement program, which is now estimated to cost $8 billion.
“Our commissioners and staff believe the scope of this investigation is broad enough to ensure all instances of misrepresentations on this matter are properly adjudicated,” ICC Chairman Brien Sheahan said in a statement. He said the commission would aggressively oversee reforms of the gas main replacement program “and will ensure that customers do not bear any costs of program mismanagement.”
Utility Seeking Developer for State’s Largest Solar Project
Madison Electric Works, a municipal utility, is seeking proposals for a 4-MW solar project to be located in the Madison Business Park. The company would buy power from the bid winner at a fixed price for between 20 and 30 years and eventually purchase the facility.
The utility, which provides electricity to about 2,300 customers in the town about 40 miles north of Augusta, says the project would cost about $8 million and would be located on about 15 acres. It would be the largest solar project in the state after Bowdoin College’s 1.2-MW solar farm.
A proposed $100 million wind project lost its final appeal before the state’s highest court, ending a six-year battle over the public’s right to enjoy views unimpeded by wind turbines.
The Supreme Judicial Court upheld the Board of Environmental Protection’s rejection of the SunEdison project, consisting of 16 turbines generating 48 MW in an area designated for wind-power generation.
Regulators had to weigh two competing aspects of state law: a developer’s right to build a wind farm in a designated zone versus the public’s right to scenic vistas from nine nearby lakes.
The Public Service Commission ordered Baltimore Gas and Electric to reduce the monthly fee for residential and small commercial customers who opt out of smart meter installation from $11 to $5.50 in January. A one-time initial opt-out charge of $75 remains in effect.
The commission ruled the lower charge was more appropriate given the current opt-out levels of 4%, compared with the predicted 1% assumption.
BGE also must report quarterly on the collection of opt-out revenues and the costs for servicing customers who choose to stay with meters that must be manually read.
The state’s clean energy sector workforce grew by 12% this year to 98,900, its strongest growth since the state began tracking these jobs in 2010, according to a new report by the Clean Energy Center.
The publicly funded center that promotes clean energy says that the sector’s employment has grown consistently for five straight years, up 64% since 2010.
Employment growth occurred statewide this year, although in the western region jobs increased by only 2.7%. The sector now represents 3.3% of the state’s entire workforce, according to the report. Slightly more than half of the companies have 10 or fewer employees.
Canada’s hydropower companies and New England transmission developers are teaming up to persuade the state legislature to pass a bill to compel National Grid and Eversource Energy to enter into long-term contracts to buy Canadian hydropower.
The consortium includes Brookfield Renewable, Hydro-Quebec, Nalcor Energy, TDI New England, Emera and SunEdison.
The import contracts would likely be handed out through a competitive bidding process. However, there’s no guarantee that the price of the hydropower, including the costs of new transmission lines, would be cheaper than the market rates for electricity.
Consumers Energy’s electric rates went up on Dec. 1 after the Public Service Commission last month approved a 4.5% rate increase that will allow the utility to recover more than $130 million annually, including funding for a natural gas plant in Jackson.
Rates will retreat slightly next April after the utility retires seven coal plants. The utility originally requested an increase of $199 million.
Entergy Mississippi is poised to lower electric rates a second time this year because of falling natural gas prices, pending approval by the Public Service Commission.
Entergy collected an excess of $48 million for fuel costs in 2015, even after a $46 million rate cut went into effect in September, according to Mara Hartmann, an Entergy spokeswoman. Under state law, utilities must pass through increases or decreases of energy costs without a markup.
Under the proposal set to go into effect in February, the monthly bill of a residential customer using 1,000 kWh/month would drop from $100 to $93.
The New Hampshire Community Rights Network, formed largely in reaction to major energy projects proposed in the state, has convinced a group of lawmakers to introduce a constitutional amendment that would grant cities and towns veto power over large-scale infrastructure projects.
The coalition consists mostly of communities that would host a portion of the Northern Pass hydroelectric project, the Kinder Morgan natural gas pipeline or industrial-scale wind turbines.
Constitutional amendments are a long shot under any circumstances, and this one faces an uphill battle, according to New Hampshire Union Leader columnist Dave Solomon.
Several top state politicians have lined up against a proposed Kinder Morgan natural gas pipeline, which would deliver Appalachian shale gas to New England. The list now includes the state’s Republican U.S. senator, both representatives in Congress and the Democratic governor.
Sen. Kelly Ayotte sent a letter to local officials in towns potentially affected by the Northeast Energy Direct proposal, telling them she will oppose the project before FERC. Gov. Maggie Hassan and U.S. Reps. Ann McLane Kuster, a Democrat, and Frank Guinta, a Republican, have also expressed opposition.
The 36-inch diameter pipeline would pass through about 80 miles of the state. Kinder Morgan re-routed the pipeline through the state after opposition formed along its original path through Massachusetts. (See Northeast Energy Direct Files for FERC Certificate.)
Xcel Energy on Dec. 1 dedicated the first section of a new 42-mile transmission line that it says will improve the state’s power system. Xcel said the 230-kV line is the first step in a major expansion of the area’s new bulk electricity transmission network.
Xcel has also recently completed a 20-mile, 115-kV project in Lea County. Both projects include more than 250 miles of transmission and distribution lines and seven new substations.
NYISO said the state’s electric system has the capacity to meet demand for power and the necessary operating reserves during extreme cold weather conditions through the 2015-2016 winter season.
NYISO anticipates a peak load demand of 24,515 MW for the winter season, comparable to last winter’s peak of 24,648 MW. The state’s record winter peak was set in 2014, during polar vortex conditions that pushed load to 25,738 MW.
Installed generation capacity in New York state this winter amounts to 41,312 MW. Net external capacity purchases, plus projected demand response, guarantees that sufficient electricity is available in the event of unanticipated power plant outages, transmission outages or unexpected increases in power consumption, NYISO said. (See Diversity Helps NYISO, but Gas Still Rules.)
The upstate town of Nassau has formed a committee to explore ways the town can install its own distributed power systems to disconnect municipal facilities from the area’s electric utility.
Supervisor David Fleming said the town suffers frequent outages during storms because of aging utility equipment. The initiative would not affect residential or commercial services, just municipal operations such as the highway garage and the transfer station. Fleming said the goal is to have all town services operate independent of the grid by 2020.
National Grid spokesman Patrick Stella said this was the first that the utility had heard that the town was contemplating removing itself from the electric grid. “We will be reaching out to the town to find out exactly what their needs are and how we can best meet them,” he said.
Solar advocates are criticizing Oklahoma Gas and Electric’s proposal to assess a demand charge on customers with rooftop solar installations as a way for the utility to protect its business model and to suppress the state’s fledgling solar market.
At a hearing before the Corporation Commission, a former Ohio regulator testifying on behalf of OG&E said the proposed tariff for new distributed generation customers was an attempt to make billing more transparent. He said it would ensure those customers pay the right amount of grid-connection costs.
The proposed tariff would affect 15 current customers. The utility proposes to charge distributed generation customers $2.68/kW of peak demand. Most households have peak usage of 6 to 8 kW, meaning the monthly charge would be $16 to $21 for a typical residential solar customer.
Commission Rejects OG&E Environmental Compliance Plan
After five months of deliberation, the Corporation Commission voted 2-1 to reject Oklahoma Gas and Electric’s application for preapproval of $1.1 billion in environmental compliance and replacement generation costs. The proposal would have increased residential customer bills 15 to 19% by 2019.
The commissioners voting against the proposal said OG&E hadn’t provided enough information to allow preapproval of its application.
OG&E wanted permission to begin charging customers for $700 million in upgrades needed to meet federal Regional Haze and Mercury and Air Toxics Standards. It also wanted preapproval to spend about $400 million to replace its aging Mustang natural gas plant in western Oklahoma City.
HIKO Energy must issue $2 million in customer refunds, pay a $1.8 million civil penalty, give $25,000 to electric distribution companies’ Hardship Fund and modify its marketing practices, the Public Utility Commission has ordered.
The penalties stem from “deceptive actions” following the polar vortex in the winter of 2013-14.
The company previously refunded $159,000 to customers it had overcharged after having promised to give them rates lower than their utility’s standard offer.
In response to public concerns about a proposed solar project, Cranston local officials have proposed an ordinance that would create “performance standards” for large-scale solar projects that would regulate noise, soil removal and decommissioning after the project’s useful life ends.
The developer of a proposed project, RES America Development, has promised that the solar farm will meet all of the conditions spelled out in the ordinance, although the legislation has not yet been enacted. RES proposes to lease land now mostly planted for corn to erect the solar farm.
Lawsuit Seeks Decision on Power Plant, Refinery Permits
Four environmental groups are suing the state to force it to approve or deny long-delayed air pollution permit applications at five refineries and three power plants. By failing to issue permits, the Commission on Environmental Quality is keeping the public from knowing how much pollution the companies are putting into the air, said Ilan Levin, spokesman for the Environmental Integrity Project.
The lawsuit says TCEQ is supposed to rule on permits within 18 months, but the commission has failed to approve permits submitted as long as six years ago. The Environmental Integrity Project is joined in the lawsuit by the Sierra Club, Air Alliance Houston and the Texas Campaign for the Environment.
Three coal-fired power generators were listed as defendants in the lawsuit: American Electric Power’s Welsh plant in East Texas, Luminant’s Oak Grove plant in Central Texas and the Sand Creek plant near Waco.
Dominion’s Plan for James River Transmission Towers Criticized
Concerned over a dwindling sturgeon population, environmentalists are opposing Dominion Resources’ plan to erect 17 transmission towers in the James River.
Dominion says the transmission line and the towers are needed because new federal emissions restrictions are forcing the company to close two coal-fired plants in Yorktown. Without the transmission line, the utility says it may have to conduct rolling blackouts during usage spikes.
The Army Corps of Engineers is in the final phase of deciding whether the proposal should move forward.
The Public Service Commission will allow Xcel Energy to increase its fixed monthly customer charge from $8 to $14. Xcel had sought an $18 monthly charge.
The moves comes a year after the PSC approved similar increases for We Energies, Madison Gas and Electric and Wisconsin Public Service, and just a month after the commission boosted the monthly fixed-rate fee for WPS customers from $19 to $21.
More than 500 commenters filed objections to the rate hike with the commission. The state is approving increases in utility fixed-rate charges at “exceptionally higher” rate than the regulatory agencies of other states, Tyler Huebner, executive director of the advocacy group RENEW Wisconsin, said in a statement.
An SPP task force preparing for EPA’s Clean Power Plan suspended its work last week, having done all it can for the time being.
The task force spent what may have been its final face-to-face meeting Friday in Dallas discussing proposed comments to EPA and a staff-developed white paper assessing rate-based and mass-based compliance. The group will present the white paper — and its comments to EPA — to the SPP Board of Directors/Members Committee on Tuesday. The comments are due to EPA on Jan. 21.
The group agreed it had met its original charge. “I think we’re done,” said Golden Spread Electric Cooperative’s Mike Wise, the task force’s chair.
“There’s not a whole lot left for this task force to do,” agreed SPP Chief Compliance and Administrative Officer Michael Desselle, the task force’s secretary.
The group determined it was too soon to address the implications of a proposed carbon-trading market or the RTO’s role in it.
The draft white paper focuses on how best to determine the supply of allowances and credits and their monitoring, verification and tracking; allocation issues; leakage under mass-based plans; and reliability implications.
SPP Vice President of Engineering Lanny Nickell has taken the point in meeting with member legislative representatives and state air regulators. He told the task force he has been involved in “broad stakeholder discussions” in every state in SPP’s footprint, with the exception of the Dakotas, Montana, Texas and Wyoming.
Left to right: Lanny Nickell, SPP; Governor Mary Fallin; Mike Ross, SPP (Source: SPP)
Nickell spoke most recently at Oklahoma Gov. Mary Fallin’s energy conference in November. Nickell said he encouraged the state to develop a compliance plan despite Fallin’s executive order in August directing state agencies not to do so.
Nickell also said he is often asked when SPP will do an analysis on the final CPP in addition to the three studies it performed based on the draft rule. Dale Niezwaag, a senior legislative representative for Basin Electric Power Cooperative, said he would welcome such a study.
However, the task force decided against an additional study.
“There are too many unknowns to do a study,” Desselle said. “With the number of unknowns and the assumptions we would have to make, it would be too expensive.”
But Wise cautioned the group, “That’s not to say we can’t change that view.”
When discussion shifted to other actions SPP might take, its associate general counsel, Matt Morais, reminded the group the RTO is also working with its peers on the ISO/RTO Council to solidify its positions and determine further actions.
“To the extent there is agreement on these issues with other ISOs, that carries a lot more weight than doing it on our own,” Morais said.
SPP Moves Closer to Making First International Transactions
SPP is preparing to conduct its first international transactions through a joint operating agreement with SaskPower, the principal electric utility in Saskatchewan. SaskPower became an SPP seams neighbor with the Oct. 1 addition of the Integrated System. (See Integrated System to Join SPP Market Oct. 1.)
Staff told the Seams Steering Committee on Thursday that the JOA is pending execution of a billing agreement for emergency energy with NorthPoint Energy, SaskPower’s marketing and billing agent. Once that agreement is executed, SPP will file with the Department of Energy for the necessary permits for international transactions.
With the recent resignations of Richard Ross (American Electric Power) and Roy Boyer (Xcel Energy), the committee has seven open positions.
SPP Sets Seventh Wind Peak in Fall
SPP, which has already set six wind-peak records this fall, established another mark Nov. 23 when it recorded 9,564 MW of wind generation at 9:45 p.m., just the second time it has eclipsed the 9,000-MW level. The RTO generated about a third of its electricity from wind at the time, below its record penetration level of 38.3%.
WASHINGTON — FERC, which faces monthly protests by global warming activists for approving natural gas pipelines and LNG terminals, was summoned to Capitol Hill last week to answer Republican criticism that it commission isn’t clearing infrastructure permits fast enough.
It fell not on Chairman Norman Bay but on the panel’s lone Republican, Tony Clark, to defend FERC’s record on natural gas before the House Energy and Power Subcommittee.
FERC Commissioner Tony Clark
Clark said that the commission had completed 92% of all applications within 12 months for the last decade. But that percentage is bound to fall, he said, because of the crushing volume of pending applications.
Since August 2014, Clark said, pending applications have spiked from 1,000 miles of pipeline with a capacity of 24 BCF/d to 4,600 miles and 50 Bcf/d. “I think it is going to be very difficult to maintain that high average when you have this volume of [applications],” said Clark, now the senior Republican on the commission with the departure in October of Philip Moeller.
While Clark talked of infrastructure, Bay focused his prepared testimony on his priorities as chairman. Commissioner Cheryl LaFleur addressed reliability and competitive markets, while Commissioner Colette Honorable spoke about FERC’s role under the Clean Power Plan.
Oversight Ritual
Congressional oversight hearings are a ritual of Washington. Each member of the committee gets five minutes to ask questions. While many members use their time to make policy statements, the best questions have often been picked clean by the time those with less seniority get their turn.
Clark faced much the same dilemma after becoming the junior member of the commission in 2012. “I don’t have any questions,” he would often tell staff presenters at the monthly meetings with a sheepish smile. “But thank you for your report.”
But with the departures of Moeller, Jon Wellinghoff and John Norris, and the arrival of Bay and Honorable, Clark is now second in seniority only to LaFleur.
At the Nov. 19 commission meeting, he settled for the first time into what had been Moeller’s seat, to the left of Bay at the head of the semi-circular table. “I’ve never been accused of being to the left of anyone on this commission,” he said to laughter. He has become increasingly assertive in the last year, both at commission meetings and in speeches around the country. (See FERC’s Clark: Energy Markets Need Tweaks, not Overhaul.)
In their opening statements last Tuesday, Energy and Commerce Chairman Fred Upton (R-Mich.) and Power Subcommittee Chairman Ed Whitfield (R-Ky.) chided FERC over what Upton called “problems with the timeliness of FERC approvals.”
They also criticized the Clean Power Plan, with Whitfield saying he is concerned “that FERC is allowing itself to become a helpless bystander as EPA increasingly dominates the electricity sector and does so in ways that serve to exacerbate the very problems FERC is supposed to protect consumers against.”
In keeping with the bipartisan ethos that has governed FERC since at least the Pat Wood era, the commission has taken pains not to get embroiled in the partisan fight over climate change and the CPP.
“Thank you for your question, congressman,” the commissioners prefaced their responses to even the most uninformed or repetitive questions.
Clark’s even-handed responses left little policy daylight between himself and his Democratic colleagues.
‘Punitive’ Target for North Dakota
But things got personal when he talked about the impact of the CPP on his home state of North Dakota.
Between the draft and final rules, Clark said, the state’s emissions reduction target quadrupled from 11% to 45%.
This, he said, even though carbon emissions dropped 11% between 2005 and 2014 and even though the state is one of only a few meeting EPA’s National Ambient Air Quality Standards.
“Utilities during that timeframe built a significant amount of wind power, in part as a hedge against carbon regulatory risk,” said Clark, whose term expires in 2016 and is rumored to have interest in running for Congress himself. “Unfortunately, it turned out to be a hedge for which they will receive no credit. Additionally, the state’s coal fleet is still relatively young, and has thus incurred recent investments for environmental compliance.”
Clark said the state’s CPP target is “so punitive that I struggle to conceive of a way it can meet it in an affordable manner,” citing a state estimate that compliance through emissions trading could exceed $400 million annually. It is, he said, “a staggering figure for a state of less than 750,000 people.”
NYISO last week asked for FERC approval to change its scarcity pricing logic, saying the proposed rules will more closely reflect the real-time value of demand response (ER16-425).
Scarcity pricing determines the value of energy and certain ancillary services when DR resources are called upon to maintain system reliability. The purpose is to ensure that real-time prices reflect the costs associated with deploying DR, the filing says.
NYISO said the filing was prompted by New York transmission owners’ concerns that its current methodology could result in uplift because of inconsistencies between prices and resource schedules.
NYISO is also proposing to increase the value of 30-minute reserves in the Southeast New York region from $25/MW to $500/MW, effective at all times. “This increase appropriately recognizes that [emergency demand response program] resources and [special case resources] have historically been called upon to protect reserves in SENY,” the ISO wrote.
NYISO is asking FERC to accept the revisions by Jan. 29, 2016, to give it enough time to develop and deploy software changes. The proposed revisions would become effective on or before June 30.
NYISO implemented its current, ex-post scarcity pricing logic in 2013. The logic allows it to adjust real-time energy prices after resource schedules have already been established in the load zones in which DR resources are used.
Generators are protesting the way in which ISO-NE calculated its installed capacity requirement for the 10th Forward Capacity Auction, saying the RTO hasn’t sufficiently vetted the way it reflects behind-the-meter solar.
In anticipation of its 2019/20 auction scheduled for February, ISO-NE filed its ICR with FERC on Nov. 12 (ER16-307).
The RTO said the only change in its assumptions from prior auctions was the inclusion of behind-the-meter solar resources that are not yet reflected in historical loads, which resulted in a 390-MW reduction in the load forecast.
In a protest filed last week, the New England Power Generators Association said the calculation should be determined by a Section 205 proceeding before FERC, after a more complete examination by the New England Power Pool.
NEPGA and Dominion Resources, which owns nuclear and gas-fired generation in the region, said that the RTO had discussed with NEPOOL stakeholders how the new methodology would be implemented but had not adequately examined related market and operational issues.
The ICR value failed to win endorsement by the NEPOOL Participants Committee, garnering a bare majority of 53%.
“A number of members expressed their opposition to those ICR values because of their view that the values were overstated because behind-the-meter PV was not properly and fully accounted for in the load forecast,” the committee said in its comments.
ISO-NE said it developed the 390-MW solar forecast with stakeholders, including state regulators, over a 10-month period.
“In order to determine the load reduction impact of [behind-the-meter] PV resources, the ISO used solar PV production data of currently installed behind-the-meter PV resources provided by the states and distribution utilities. The ISO calculated the PV already embedded in load and then adjusted the load forecast by the forecasted” resources, the RTO wrote.
The New England States Committee on Electricity, which last year challenged the exclusion of distributed solar resources from the ICR calculations, supports ISO-NE’s current ICR filing.
“The ICR … must consider in a timely manner the rapid development of solar PV resources that are affecting system demand,” it said in its comments. “New England consumers are increasingly investing in clean, distributed energy resources in furtherance of state energy programs and policies. The ICR cannot be divorced from these significant investments in solar PV resources.”
Despite its own characterization of the plant’s history as troubled, the Nuclear Regulatory Commission issued a 20-year license extension to FirstEnergy’s Davis-Besse nuclear plant in Ohio. NRC reviewed the plant’s operational record for five years, substantially longer than most license-extension reviews.
The Nuclear Regulatory Commission has told Entergy it can continue to operate the Indian Point nuclear power plant’s Unit 3 under its existing license while its license renewal review continues.
FERC has told the developers of the $5.1 billion Atlantic Coast Pipeline project that they should look for alternative routes through the Monongahela and George Washington national forests on the West Virginia-Virginia border.
FERC is being asked to issue a certificate of convenience to a proposed natural gas pipeline that would deliver shale gas from Ohio to customers in Michigan and Canada.
Also included in the study is Exelon’s two-unit Nine Mile Point. The company has not indicated that the plant is in danger of closing but said its environmental attributes need to be recognized in the design of the wholesale market.
