An increase in demand response, low load growth and market incentives have the nation’s power system in good shape heading into the winter, NERC said in its Winter Reliability Assessment last week.
“NERC-wide, sufficient margins are in place. Most assessment areas experienced little to no load growth, and demand response programs … continue to grow,” Tom Coleman, NERC’s director of reliability assessments, said during a conference call Thursday. “Winter of 2015 posed some challenges, but the system addressed these conditions, learning … from previous years’ lessons.”
“Total internal demand continues to trend downwards and is significantly augmented by the advancement of new energy efficiency programs, distributed energy resources and behind-the-meter generation (BTMG) resources that are being incorporated into planners’ load models and forecasts,” the report said.
While total DR is increasing 2.6 GW to almost 25 GW, NERC reported, resources available in the winter have doubled from about 10 GW to 20 GW.
“The addition of new demand response programs continues to help address potential resource adequacy concerns for areas during their winter peak,” according to the report. “These programs vary greatly in their availability and load reduction capability, but often provide the flexibility needed during extreme conditions.”
The winter-peaking Midwest Reliability Organization-Saskatchewan Power region boosted its winter DR to 244 MW from 158 MW a year ago. PJM, which formerly had only summer DR, has added a year-round product and will have 525 MW available for the winter peak, versus last winter’s 43 MW. (See related story, SPP: Ready for Winter.)
Coleman noted the increased coordination between natural gas suppliers and generators this year is a big improvement over the past two winters, when some generators in ISO-NE and PJM experienced difficulty obtaining gas in times of high demand.
He cited FERC’s approval of New England’s 2015/16 Winter Reliability Program, which established incentives for generators to procure on-site fuel before winter and another program encouraging generators to sign contracts for LNG. A dual-fuel testing and commissioning program will also provide incentives for generators.
NERC also noted readiness improvements in PJM, including pre-winter generator testing and winter preparation checklists as well as better communication on fuel status and improved coordination with natural gas pipelines.
Despite a net loss of 6,163 MW of installed capacity since last winter, NERC said PJM is in good shape, with an anticipated reserve margin of 40%, well above its own 15.6% requirement. (See PJM Prepared for Winter Load, Mild Temps Expected.)
“Because of the nature of the [three-year] forward capacity market in PJM,” NERC said, the benefits of its Capacity Performance rules “will not be seen until the winter of 2016/17.”
MISO’s Board of Directors last week approved the 2015 Transmission Expansion Plan, which calls for $2.75 billion in spending on 345 projects through 2024.
Board member Michael Evans said MTEP15 was shaped by more than 40 pages of stakeholder comments. “I think it got a thorough vetting and we’re happy to see the level of interest from stakeholders,” he said.
MTEP15 includes MISO’s first competitively bid project, the Duff-Coleman 345-kV line in Southern Indiana. MISO will fund the $67.4 million cost of the Duff-Coleman portion while PJM be responsible for the $85.3 million needed for the double circuit 345-kV tie-in to Rockport.
Evans said MISO’s competitive bidding is “an impressive process, but it’s also a new process so I expect we’ll encounter some bumps along the way.” He assured the room that the bidding, which begins next month, will comply with FERC Order 1000.
Evans added the projects that “slipped” and didn’t make the final plan were typical of the process and won’t affect reliability.
“Lest we forget, the volume of work that goes into this is huge. Some 60 meetings were held over the last 18 months to get this thing done,” Evans said.
MISO South’s share of approved projects represents $1.4 billion, more than half of the total portfolio.
MISO Board Approving MTEP15
It includes the $122.5 million East Texas economic project, a 230-kV transmission line from Lewis Creek to a new 345/230-kV substation and the rebuild of the Newton Bulk-Leach 115-kV line.
Also of note in the plan are Louisiana’s $122 million Schriever to Bayou Vista 230-kV line, the $114 million New Plains-National 138-kV line in Upper Michigan and the $97.8 million construction of two 120/41.6-kV substations to serve load in Ann Arbor, home of the University of Michigan.
“There’s an awful lot of good stuff in there. When your Christmas gifts are wrapped, you might want to read it,” board member Judy Walsh said of the 429-page document.
“These investments in the region will continue to position MISO for future challenges and changes in the industry,” said CEO John R. Bear. “As our region grapples with the Clean Power Plan and a shifting generation portfolio, MISO’s transmission planning efforts are even more important. Ensuring a robust transmission system will allow us to meet these challenges in a way that protects reliability.”
With the addition of MTEP15, transmission investment in the footprint will increase to 863 projects totaling about $12.9 billion since 2003.
Board OKs 2016 Budget; MISO Overspends by a Slight Margin in 2015
MISO will exceed its 2015 budget by as much as 1.3%, the Board of Directors was told last Thursday.
As of October, MISO had operating expenses of $185.2 million, an overrun of $2.4 million, reported Tonya Brown, executive director of finance and corporate services. The RTO is projected to spend an extra $1.8 million to $2.8 million by year-end.
During the first 10 months of 2015, spending on capital expenses came in under budget by $1.6 million or 7.8%; MISO spent $19.1 million instead of the allotted $20.7 million. However, the grid operator is forecasted to spend $24 million to $24.2 million instead of the budgeted $23.5 million by the end of the year.
The board unanimously approved the 2016 spending plan, a $225 million operating budget and a $31 million capital budget.
Cash reserves are predicted to drop over the next five years, reducing the expected $79 million MISO will have at the end of this year to $13.5 million in 2019 before rebounding to $46 million in 2020. Factors contributing to the reduction are the conclusion of recovery of depreciation on ancillary markets and the 2016 start of principal payments on debt.
Board member Thomas Rainwater reported that MISO’s costs have grown at a compound average rate of 3% while load has increased 30% over the past decade.
New Board Members Elected
MISO’s board agreed to add two new members to its Board of Directors: former general manager of Pasadena Water and Power Phyllis Currie and former vice president of transmission operations for Pacific Gas and Electric Mark Johnson. Additionally, board member and former chairman and CEO of the Boston Stock Exchange Michael Curran was re-elected to another three-year term, and board member Eugene Zeltmann, whose term expired, announced he would not seek another term. With the new appointments, MISO’s board expands from seven to nine seats.
Tx Developers Urge ‘Proactive’ Role; OMS: Respect State Jurisdiction
By Amanda Durish Cook
CARMEL, Ind. — MISO stakeholders are deeply split over how proactive the RTO should be in helping its 15-state region comply with the Clean Power Plan.
At an Advisory Committee “hot topic” discussion last week, some stakeholders cautioned MISO against taking policy positions, while others said the RTO should help guide the states to the most economical compliance options.
“MISO is going to have to live with what the states decide,” said Texas Public Utility Commissioner Kenneth Anderson, whose state is among 11 in MISO whose officials have joined in legal challenges to the EPA rule. “Until real decisions are made, you run the risk of running into political minefields. Whether we do rate-based or mass-based [compliance], there are going to be very different consequences.”
No Advocacy Role
The Organization of MISO States also urged MISO to follow rather than attempt to lead the states. “Ultimately, MISO will be charged with incorporating the states’ decisions on CPP compliance into its markets, planning and operations. If those decisions result in some states choosing to ‘go it alone,’ some choosing to be trading-ready, some choosing rate-based or mass-based compliance, or taking legal action against the EPA, such decisions are the states’,” OMS said in its written comments. “MISO should focus on how to best operate a reliable system in these conditions.”
The End-Use Customer sector agreed that MISO’s role should “be limited to providing information and analysis on the cost and reliability impacts” of compliance options “rather than taking on an advocacy role.”
But others urged MISO to help steer the states, with the Environmental sector saying the RTO should “encourage states to adopt consistent, complementary plans that include coverage of new sources and facilitate broad trading opportunities.”
The Public Consumer sector said MISO should provide each state a comparison of rate-based and mass-based compliance “so the lowest-cost and lowest-risk compliance options are clearly identified.”
The Competitive Transmission Developers sector also pushed for a proactive role, saying “it is time for MISO’s role to shift from information dissemination to collaboration and active planning to facilitate state compliance efforts.”
Kari Bennett, MISO
“Without a proactive and accelerated RTO planning effort to ensure necessary transmission infrastructure can be put in place across the region, the ability of each member state to meet compliance requirements could be heavily restricted (if not jeopardized) due to reliability concerns, in addition to the potential loss of efficiencies currently provided by the MISO market,” it said.
Stakeholders also were divided on whether MISO should file comments with FERC on EPA’s proposed federal implementation plan. “MISO has not made any decisions on if we will comment,” said Kari Bennett, MISO’s senior corporate counsel.
Bennett said MISO will not seek to advocate or condemn any state compliance plans and that modeling would be based on “dispassionate calculations.”
But MISO Director Eugene Zeltmann said it might be difficult to entirely wipe out any public policy in CPP modeling. “There’s going to be some very sterile modeling going on,” he said.
MISO Role in Trading
Although there is wide agreement that compliance will be least costly if it includes a broad regional emissions trading program, MISO’s role in trading is uncertain.
The Transmission Owners sector said MISO should look to existing programs such as the Midwest Renewable Energy Tracking System, rather than developing its own trading platform. “There are existing markets … for trading allowances and credits,” the TOs said. “These markets will perform very well.”
The Independent Power Producers sector said MISO “should not have a role in implementing any multi-state implementation plans,” saying both the Regional Greenhouse Gas Initiative and California’s cap-and-trade program “require no interface with the RTO/ISOs beyond allowing suppliers to price the cost of emissions compliance into their offers.”
Many Unknowns
Next month, MISO expects to release its near-term analysis, which will evaluate the implications of various compliance paths based on models used in prior analyses of the draft CPP, with updates reflecting the final rule.
The mid-term analysis, expected to run through June, will use new models based on the most relevant compliance paths from the near-term study to determine likely resource buildouts and their locations under three separate futures. It will be the foundation for transmission development under the 2017 MISO Transmission Expansion Plan.
With state compliance plans unknown, there are limits to what MISO can model, said Clair Moeller, MISO executive vice president of transmission and technology.
Most states are expected to seek a one-year delay from EPA, meaning their compliance plans won’t be filed until November 2017, when MISO will be in the middle of its long-term analysis. EPA will impose a federal plan on states that fail to present an acceptable plan of their own.
Detailed modeling would have to wait “until the states start to tip their hand one way or the other,” Moeller said. “We’re going to run out of time like we always do. There’s going to be a panic in 2017, but we’re going to do all we can.”
Challenges will arise to fit state plans into regional markets, stakeholders said. Several AC members pointed out that Wisconsin is the only state within MISO whose borders are completely within the RTO’s footprint.
“I don’t think we’re going to model our way into quantitative comfort,” Director Michael Curran said. “We may model ourselves to a level of frustration with each other.”
More transmission will likely be needed under any compliance scenario, several stakeholders said.
“MISO should not wait for all state plans to be filed before beginning work on the transmission studies, including overlay studies,” the TOs said, urging MISO to quickly identify “no regrets” transmission projects likely to be needed under a variety of scenarios.
MISO’s Environmental sector pointed out that the Midwest is home to the nation’s best onshore wind resources. “Planning to quickly, affordably and reliably tap into these wind resources and deliver them to market can be done more effectively if interregional planning processes are improved,” it said. “More action is necessary to identify the transmission necessary to access and transport the energy to MISO and other regions.”
Modeling Priorities
Some stakeholders expressed dissatisfaction with MISO’s modeling priorities.
The TOs said MISO should focus on “providing an impartial comparison of the different means and approaches to full compliance and its impacts on reliability and efficiency of the grid.” They said that scenarios for partial and accelerated compliance would provide only “marginal” benefits.
“The accelerated compliance scenario, while still possible, is highly unlikely, even with technology breakthroughs, given the short timeline,” it said. “Even if, ultimately, more aggressive long-term goals for greenhouse gas abatement were to be adopted, they would likely be sought through steeper reductions in the outer years. Second, a partial compliance scenario may have some value, particularly if scoped as a delayed implementation scenario to account for legal challenges, but MISO should avoid spending too many resources and/or time on this.”
The End-Use sector said MISO should increase its coordination with neighboring SPP and PJM and “benchmark” the results of its analyses against those of the other regions. The sector said MISO should expand its modeling to include not only cost estimates for generation and transmission that may be needed, but also an evaluation of whether the region has sufficient natural gas infrastructure to accommodate the anticipated increase in gas-fired generation.
The Environmental sector said MISO should “more comprehensively model compliance strategies that rely on increasing energy efficiency (EE).”
“Without modeling high EE scenarios, states will not be able to understand the cost and emissions implications of expanding their EE programs as a strategy to comply with the CPP,” it said. “For example, in rate‐based compliance approaches, excluding EE from the supply will artificially constrain the supply of emissions reduction credits (ERCs) and increase ERC prices. Modeling EE simply as lower demand growth would not allow for its incorporation into a rate‐based plan in this manner, and thus would skew model results.”
Changes Coming
The Transmission-Dependent Utilities sector said MISO may need to change some market rules. It said a seasonal capacity construct, now under discussion, could aid compliance. (See MISO Proposes Two-Season Capacity Market, Appoints Team to Address Ill. Zone.) “Entities may choose to only run their coal-fired units during peak demand periods in the summer, and use natural gas as much as possible in shoulder periods,” it said.
It also said MISO should be prepared to replace spinning reserves, black start services and reactive power services provided by baseload units that may retire or limit operations.
The shift from coal- to gas-fired generation argues for a move to a multi-day resource commitment, it said.
“The current next-day economic commitment process can lead to higher costs by not committing long-lead time resources, which are economical over longer periods. A longer commitment process will help to address this issue and improve the economic operation of gas-fueled generation by providing a longer lead time to procure fuel.”
The competitive transmission developers said MISO should “conduct accelerated discussions” with stakeholders on how the RTO will allocate costs of transmission improvements needed for compliance. “Currently, there is too little flexibility in the MISO Tariff to allow for sub-regional or state-based cost allocation for public policy projects, which could impede necessary development if left unaddressed,” they said.
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%.
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.
