PJM generation owners conducted winter preparation tests of 156 infrequently used power plants between Dec. 5 and Jan. 2, cranking up 7,549 of a possible 9,349 MW for a success rate of 81%.
Units failed to start due to problems with fuel-handling systems and emission systems, as well as oil leaks, tube leaks and cranking diesel generator failures, PJM officials told the Operating Committee last week. The tests were considered successful if the units were able to generate installed capacity levels, even if it took two or three attempts to get them running.
Warm weather in December forced numerous test cancellations and pushed the testing into January. An additional 18 units (980 MW) were scheduled for testing last week.
The testing will result in more than $3 million in make-whole payments, officials said.
Operators of 91% of generating units — representing 98% of installed capacity — reported to PJM that they had completed their own cold weather checklist or the one in PJM Manual 14D.
PJM will seek stakeholders’ input on ways to encourage interconnection customers to file their requests earlier, officials told the Planning Committee last week.
A more granular review of PJM’s interconnection queue over the past 14 years indicates that about 80% of requests are for new generation projects, and that 15% of those are now in service. Proposals for upgrades had a 58% success rate, said David Egan, manager of interconnection projects.
The review, which excluded active projects, looked at queues A through AA1 since 2000, when the queuing process began.
The review was sparked by last month’s queue status update, which showed that PJM’s new graduated queue-entry cost structure had failed to persuade developers to file applications earlier. (See PJM: Interconnection Customers Still Procrastinating.)
Under the new structure, the deposit for applications filed in the first four months was set at $10,000; for the fifth month it was set at $20,000; and for the last month, $30,000. Despite the cost increases, most developers waited until the last days to file, leading to an uneven work load for project managers.
“We’re not jumping to any immediate changes but will be coming back with further discussion,” said Steve Herling, vice president of planning. “We’ll be coming up with a problem statement. We now have a much more complete picture of these queues.”
The 2,394 project applications in the queues represent 289,742 MW, according to Egan. Of those, 30,546 MW (11%) are in-service and 16,360 MW were withdrawn.
Duke Energy plans to make its first substantial purchase of solar power in Indiana, giving customers the option to buy “locally sourced” solar energy credits to help cover the cost.
The utility, with more than 800,000 customers in 69 counties, asked the Indiana Utility Regulatory Commission on Dec. 29 (Docket No. 44578) for permission to acquire a total of 20 MW of power from four solar farms: 5 MW each from Geres Energy, McDonald Solar, Pastime Farm and Sullivan Solar.
The sites are under construction, or soon will be, in Clay, Howard and Sullivan Counties. They’re set to go on line by the end of 2016.
The 20 MW of solar power is miniscule for a utility with more than 7,500 MW of mostly coal-based generating capacity in Indiana. But it amounts to the first utility-scale solar commitment for Duke in Indiana, spokesman Lew Middleton said.
Beyond Net Metering
Virtually all Indiana-generated solar power entering Duke’s system is currently on a net-metering basis. According to the IURC’s 2014 net metering report, Duke Indiana had 241 customers with their own solar panels that generated 1,458 kW in 2013. That year Indiana ranked 19th in the nation for photovoltaic solar deployment, with only about 88 MW installed, according to the Solar Industry Association.
The proceeds from the sale of renewable energy credits (RECs) would be applied toward the ratepayers’ share of the cost to buy energy from the solar farms.
Middleton said it’s too early to say how much it will cost customers to buy the solar renewable energy credits.
A REC is a tradable instrument that represents the environmental attributes of electricity generated from renewable energy. The credits are distinct from the electricity commodity, allowing them and the actual electricity to be traded separately, Duke said.
Customers would be able to buy the solar RECs through an expansion of Duke’s GoGreen program. Currently, that program allows customers to buy at a premium blocks of wind-generated power, for a minimum of $1.80 a month.
Since 2006, customers opting to participate in the program have supported 43 MWh of wind energy, the utility says. About 1,322 customers — or less than 1% of Duke’s Indiana customer base — participate in GoGreen.
But in its filing with the IURC, Duke said a number of customers have expressed interest in locally sited renewable projects, as opposed to out-of-state RECs.
It also touted the plan as diversifying its generation portfolio and fostering economic development.
Indiana’s nascent photovoltaic deployment got a boost in 2013, when a 12.5-MW solar farm was constructed at the entrance to Indianapolis International Airport. Subsequently, another 10 MW of panels were added, making it the world’s largest airport solar farm. Indianapolis Power & Light purchases the power under a feed-in tariff.
More Solar
Under Duke Indiana’s 2013 Integrated Resource Plan “blended approach” scenario, the utility envisions potentially 2,000 MW of nameplate wind capacity and 330 MW of solar by 2033.
The Charlotte, N.C.-based utility notes that solar is the least-expensive renewable fuel source and typically amounts to more reliable capacity during summer peaking conditions than wind.
Much of Duke’s renewable activity has been focused at its Duke Energy Renewables unit, an arm of its commercial division. DER owns 150 MW of capacity at 21 solar farms. It also owns or has a management role in 15 wind farms totaling 1,800 MW in 12 states.
Solar power remains a tiny but growing portion of the energy mix in the Midwest. In the MISO region, renewables comprise about 12% of generation, and most of that consists of 13,000 MW of wind generation.
The price to install photovoltaic systems has fallen more than 34% since 2010, according to the Solar Industry Association. That’s piqued interest in solar even in Midwestern states such as Wisconsin, where solar is just one-tenth of 1% of the state’s installed generating capacity.
Yet several Wisconsin utilities last year, including Milwaukee-based We Energies, proposed to increase fixed costs customers pay on monthly bills and reduce how much they pay customers for their own solar generation fed back to the grid.
Utilities argue they need more revenue to cover their fixed costs as customers generate more of their own power and reduce consumption through energy efficiency efforts.
Duke Energy is facing opposition to plans to dispose of coal ash in abandoned clay pits in two North Carolina counties. Commissioners in Chatham County passed a resolution against the disposal plan in December, and Lee County commissioners did the same thing last week.
Duke, which has committed to cleaning up coal ash dumps and ponds at four retired generating stations within five years, says storing the ash in the abandoned surface mines is an environmentally responsible and safe plan. It says the landfills would be lined and capped. “This is a very industry-tested, safe application of how to dispose of this material,” said Duke spokesman Jeff Brooks.
Environmentalists are skeptical. “It’s not a matter of ‘if’ it will leak; it’s a matter of ‘when,’” said Therese Vick of the Blue Ridge Environmental Defense League.
FirstEnergy’s Davis-Besse Nuke Generates $1 Billion for Ohio
Davis-Besse Nuclear Power Station (Source: FirstEnergy)
The Davis-Besse nuclear power plant generates about $1 billion annually for the Ohio economy, according to a study by the Nuclear Energy Institute.
Richard Myers, the NEI’s vice president for policy development, said FirstEnergy commissioned the organization to produce the report in anticipation of using the information when it next goes before the Public Utilities Commission of Ohio for a long-term rate plan.
“This study confirms that Davis-Besse greatly strengthens the local, regional and state economies through job creation, tax payments, and direct and secondary spending,” Myers said.
Two western uranium miners are merging operations, spurred by a sluggish market for yellowcake uranium, which is refined into nuclear fuel.
Uranerz Energy, of Casper, Wyo., is merging with Denver’s Energy Fuels Inc. Uranerz shareholders will control 55% of the new company, which will adopt the Energy Fuels name.
Uranerz operates a mine in northeast Wyoming in which the uranium is extracted by “in situ leaching,” a process in which water is injected into rock and then pumped to the surface where the uranium is separated from the liquid. Energy Fuels operates a mine in Utah that employs conventional mining of uranium ore.
Nicole Kivisto is the new president and CEO of MDU Resources Group, the company that owns Montana-Dakota Utilities, Great Plains Natural Gas, Cascade Natural Gas and Intermountain Gas. Together, the companies serve 1 million electric and natural gas customers in Washington, Oregon, Idaho, Montana, Wyoming, Minnesota, North Dakota and South Dakota.
A native of North Dakota, Kivisto replaces K. Frank Morehouse, who resigned.
The owners of two small wind farms in Minnesota have filed for bankruptcy protection, putting the investments of a consortium of 360 farmers at risk.
Minwind Energy said expensive repair costs and a paperwork error that leaves them open to a possible federal fine of $1.9 million mean it no longer has enough money to run the wind farms.
The farms have 11 turbines, went online in 2002 and 2004, and were profitable until 2012. Most of the facilities’ energy is sold to Alliant Energy and Xcel Energy.
Entergy Spending $187 Million on Lake Charles Tx Project
Entergy Gulf States Louisiana has filed with the Louisiana Public Service Commission to build a transmission line and two substations to bolster service reliability in the Lake Charles area.
The 25-mile line is designed to supply an estimated 500 MW of load growth in the area in the next few years. Another 500 MW of load could develop in the near future, Entergy officials said. The company said construction would begin in 2016 and be completed in 2018.
Duke, Dominion Set Records During Cold Wave Last Week
Duke Energy Progress, the electric utility serving customers in parts of North Carolina and South Carolina, set a record for winter power use during last Thursday’s frigid temperatures.
The new peak of 14,473 MW was set for the hour ending 8 a.m. The previous record was 14,190 MW set last Jan. 7, during the Polar Vortex. Duke asked customers to conserve when temperatures began to plunge. By 8 a.m., the temperature in Charlotte, N.C., dipped to 8 degrees Fahrenheit.
Dominion Virginia Power’s 2.1 million customers also set a new winter peak during last week’s cold snap.
The utility’s load climbed to 19,870 MW at about 8 a.m. Wednesday. That eclipsed the previous record of 19,785 MW set on Jan. 30 of last year.
Hawaiian Electric Shareholders to Vote on Acquisition by NextEra in Spring
Shareholders of Hawaiian Electric Industries will vote this spring on NextEra Energy’s $4.3 billion offer for subsidiary utility Hawaiian Electric.
The acquisition also needs the approval of the Hawaii Public Utilities Commission. The companies say they expect to close the deal by the end of this year. The merger was announced late last year.
Clean Line Facing More Opposition to Illinois Transmission Line
Clean Line Energy’s Grain Belt Express, a proposed 750-mile direct-current transmission line designed to deliver wind energy from Kansas to markets east, is facing mounting opposition in Illinois.
A public meeting on the plan in Jacksonville, Ill., last week was attended not only by landowners whose property the 600-kV line could cross, but activists from three other states with experience in fighting Clean Line projects. A group calling itself Block GBE Illinois is forming to help coordinate opposition.
A company spokesman said Clean Line was committed to an “open, transparent process that keeps landowners, the public, elected officials, community leaders and the media informed about all facets of the project’s planning and construction process.”
Negotiations that could determine the future of an upstate New York nuclear power plant are set to conclude this week, following a 60-day schedule set out by state regulators.
The New York Public Service Commission in November ordered the owner of the 580-MW R.E. Ginna plant on Lake Ontario to negotiate a temporary contract with the local utility, Rochester Gas & Electric.
The plant has been deemed necessary to maintain system reliability in western New York in a study ordered by the PSC.
However, plant owner Constellation Energy Nuclear Group, a unit of Exelon, said it has lost $100 million over the past three years and will mothball the plant if it can’t get higher prices for its output.
The PSC wants the companies to negotiate a reliability support services agreement (RSSA) in which RG&E would buy Ginna’s output, which is currently sold at a loss into the NYISO wholesale market, according to Constellation. A negotiated settlement is due on Thursday, or the parties must inform the PSC they were unable to reach one.
Spokesmen for both Constellation and RG&E said negotiations are continuing but would not discuss details.
Ginna was formerly owned by RG&E but was sold to Constellation in 2004. The plant, which is licensed through 2029, had a 10-year power purchase agreement with RG&E that expired last June.
Rochester-area customers are likely to face higher electricity costs regardless of the outcome. A higher, above-market price would presumably be negotiated with Constellation, or if Ginna is eventually taken offline, the reduced supply will drive up prices in the western New York region.
Entergy, another nuclear power generator that owns the Indian Point Energy Center north of New York City, has opposed the RSSA. It argued, unsuccessfully, that Constellation has effectively tried to file a retirement notice without the proper procedures, time and expense any other nuclear power plant owner would be required to do under similar circumstances. It also said an RSSA presented directly to the PSC would not permit review and comment, to which other “must-run” agreements are subject.
RG&E, a subsidiary of Iberdrola USA that serves 371,000 electricity customers in a nine-county region, said it would face reliability issues anytime its load exceeded 1,430 MW. Its modeling indicates that would occur at least for 205 hours per year.
RG&E said a transmission project expected to be in service in late 2018 will shorten the length of the Ginna agreement.
The $250 million Rochester Area Reliability Project will access power from the New York Power Authority’s 345-kV cross-state transmission lines originating in Niagara Falls.
It includes 1.9 miles of new 345-kV transmission, 23.6 miles of new or rebuilt 115-kV lines, a new 345-kV/115-kV substation and equipment upgrades. The project was first intended to maintain reliability in the event of a long-term outage at Ginna.
Illinois officials last week offered state legislators a list of options for keeping Exelon’s nuclear plants running — including a carbon tax and a cap-and-trade program — all of which will likely result in higher power prices for consumers.
The options came in a 269-page report issued by the Illinois Commerce Commission, the Illinois Power Agency, the Illinois Environmental Protection Agency and the Illinois Department of Commerce and Economic Opportunity. A state House of Representatives resolution tasked the agencies to come up with the report, and to include “potential market-based solutions to guard against premature closure of at-risk nuclear plants and associated consequences.”
Exelon last year said that three of its nuclear generating stations — Byron, Clinton and Quad Cities — have been unprofitable in the current market, and the company threatened to shut them down if changes weren’t made. The company has said government subsidies and tax credits given to the wind and renewable energy sectors result in an unfair market advantage for those generators. It also has repeatedly said it is not looking for a “bailout” of the plants, instead arguing that the nuclear stations should get credit for producing carbon-free electricity.
Much of the Illinois report is concerned with the potential costs to the state if the plants are retired. Faced with the loss of jobs and tax revenue if they close, and the possibility of having to burn more fossil fuels to make up for the lost generation, the agencies suggested a series of programs and taxes that would penalize fossil fuel burners and provide incentives to Exelon to keep its nuclear plants open:
Do nothing, and rely “purely on the market and external initiatives to make corrections;”
Establish a cap-and-trade program with other states, which would monetize the carbon-free nature of nuclear generation;
Tax those generators that do burn fossil fuels and produce carbon emissions;
Adopt a low-carbon portfolio standard; or
Adopt a sustainable power planning standard.
Higher Prices, Job Losses
No matter what policy is adopted, ratepayers would probably end up paying more, either through having to fund the subsidies through taxes or by being hit with higher energy bills. The costs of plant closures alone, not taking into account the effect on rates or the wholesale market, are substantial, according to a section of the report by the Commerce Department. The agency predicted 2,500 direct job losses at the nuclear plants, 5,300 indirect job losses, more than $1.8 billion in annual lost economic activity and a 10 to 16% increase in wholesale power prices.
Replacing the nuclear capacity with more than 7,000 MW of wind and 1,500 MW of solar by 2020 would create more jobs initially — 9,600 — but much of that would be temporary construction work, resulting in a net loss of more than 5,000 jobs.
That there would be an impact on costs upon retirement of any of the plants is undisputed, according to the report. A PJM analysis adopted by the report shows a jump of up to 9.9% in energy costs in the RTO’s Commonwealth Edison zone if all three plants were retired. Spread out over all zones of PJM, the increases are less pronounced, topping out at about 3.5% if all three plants retired.
Reliability Impact
The cost of the decrease in reliability is difficult to quantify, according to the report, but would easily be “in the hundreds of millions of dollars or more.” The cost of making substantial changes and improvements to the transmission system alone, and changing Illinois from a net exporter of electricity to a net importer, would be an additional burden — also measured in the hundreds of millions of dollars.
“There is a potential for impacts on reliability and capacity from the premature closure of the at-risk nuclear plants,” the Illinois Power Agency said. “However, in many of the cases analyzed, reliability impacts remain below industry standard thresholds, and impacts appear to be more significant in other states than in Illinois.
“Taken alone, there may not be sufficient concern regarding reliability and capacity to warrant the institution of new Illinois-specific market-based solutions to prevent premature closure of nuclear plants. But combined with the issues raised by the reports prepared by the ICC, IEPA and DCEO, the totality of the impacts suggest that the General Assembly may want to consider taking measures that would prevent the premature closure of at-risk nuclear plants.”
The environmental costs are briefly outlined in a section of the report, with an analysis done by PJM at the request of the ICC. The RTO estimated that if all three plants closed, the resulting increased dependence on fossil generation would lead to “increased carbon dioxide emissions of up to 18.9 million tons across the PJM region and up to 8.7 million tons for the state of Illinois.” The Illinois EPA wrote that it estimates the costs to society of replacing the nuclear generation with another, fossil-heavy mix — what it calls the Societal Cost Carbon Estimate — at between $2.5 billion and $18.6 billion from 2020 to 2029.
Plants’ Profitability
A large portion of the report consists of cost analyses and revenue examinations, with a multitude of factors in an attempt to determine if, in fact, some of Exelon’s nuclear stations are unprofitable. “Because of the limited cost data available, it is not entirely clear whether or not Exelon’s Illinois plants earn sufficient revenues to cover their operating costs,” the report concludes. “As shown, some of the Illinois nuclear units would require no price increase — relative to the 2007-2013 price averages — to restore profitability.”
The report said price increases expected under the U.S. EPA’s proposed carbon emission rule — estimated at 10 to 20% — will improve the profitability of Exelon’s nuclear units. But that would not be enough to save Quad Cities, which would need a 50% increase to become profitable.
The report also predicts that nuclear units will benefit under PJM’s Capacity Performance proposal because of their low forced outage rates.
Carbon Tax
As one solution, the report suggests a carbon tax, which would generate a revenue stream while also providing an incentive through market signals for low- or carbon-free emission generation.
Another suggested solution is that the state convert its renewable portfolio standard to a low carbon standard that includes nuclear power among favored generation sources. As under RPS, wholesale purchasers of electricity would be required to obtain specified percentages of their supply from sources with lower carbon intensity than that of fossil-fuel generation.
Exelon’s Response
Exelon issued a written statement yesterday morning, in which it quoted parts of the report that supported its view of the need to develop a policy to keep the nukes running.
“We thank the state for its attention and work on such an important issue for Illinois and the future of the state’s energy assets,” the statement reads. “The report makes clear that the future of Illinois’ nuclear power plants should be an issue of statewide concern.
“We continue to believe that the best, most cost-effective approach for preserving the benefits these plants provide is a market-based solution that properly values the emissions-free, always-on energy they generate.”
No to ‘Bailout’
Howard Learner, executive director of the Environmental Law & Policy Center, said the report “shows that Exelon’s nuclear plants that aren’t economically competitive can be retired without added costs to Illinois consumers, without hurting reliability and with more job creation by growing clean renewable energy and energy efficiency.”
“This report confirms that the competitive power market is working to hold down Illinois energy costs,” Learner said. “We shouldn’t bailout Exelon’s old, uncompetitive nuclear plants. Instead, we should invest in new renewable energy, like wind and solar, and energy efficiency to grow a cleaner Illinois energy future.”
The Environmental Protection Agency will delay its three proposed carbon emission rules until mid-summer, as it coordinates their release to address new, existing and modified power plants during the same time frame.
The agency’s final carbon emission standard for new power plants was to have been issued within one year of its publication in the Federal Register on Jan. 8, 2014. The EPA said that was impractical given the volume of public comments received and the overlap that will result from the three sets of rules for electric generators.
“There are cross-cutting topics that affect the standards for new-source, modified sources and for existing sources,” Janet McCabe, acting assistant administrator for the Office of Air and Radiation, said at a press briefing Wednesday.
The rule for existing power plants, the Clean Power Plan, was proposed last June, setting up a deadline of June 2, 2015, for them to be finalized. However, the EPA extended the public comment period for 45 days in September, and in October it issued a Notice of Data Availability, indicating its willingness to consider a slower shift from coal to natural gas generation. (See EPA Signals Flexibility on Interim Carbon Targets, Coal-Gas Shift.)
McCabe said those changes, and the need to consider the more than 4 million comments received in response to all of the rules, prompted the delay. The comment period on the Clean Power Plan ended on Dec. 1, six weeks after the Oct. 16 deadline for comments on the proposed rules for modified and reconstructed power plants.
“We think these additional few weeks will give us the time we need to review the extensive public comments on all three proposals and finalize a suite of rules that takes into account all of these cross-cutting issues,” McCabe said.
The EPA will also be starting a rulemaking process on a federal implementation plan for existing generators to guide states that are formalizing their response to the Clean Power Plan. That process is to begin soon with the aim to also issue the federal plan proposal in mid-summer.
McCabe said the EPA had been approached by states to see if a model rule was going to be proposed. The federal plan also would stand in place for states that balk at producing their own plans.
“EPA’s preference is that states submit their own plan tailored to their specific needs,” McCabe said.
Some observers say combining the three proposals may help them withstand legal challenges and attacks by Congress’ Republican majority.
The plan for new generators essentially prevents new coal-fired generators that don’t employ carbon capture and sequestration, an expensive and largely unproven technology. (See EPA GHG Rule May Turn on Viability of Carbon Capture.)
The plan for existing generators has raised concerns that it will lead to another wave of coal generator retirements in addition to those shuttering in response to the EPA’s Mercury and Air Toxics Standards. (See FERC to Hold Technical Conferences on EPA Clean Power Plan.)
PJM wants a one-time waiver to avoid releasing 2,000 MW of capacity for the 2015/16 delivery year, when the RTO fears it may run short of resources due to retirements of coal-fired generation.
PJM officials told the Markets and Reliability Committee Dec. 18 that they would seek to postpone generation retirements — or accelerate planned new generation — to help the RTO ride through potential shortages next winter. (See PJM Seeks to Postpone Some Generation Retirements through 2015/16.)
On Dec. 24, PJM made two filings with the Federal Energy Regulatory Commission to put its plan in action.
In one, PJM asked for a one-time waiver on rules that would otherwise require it to release 2,000 MW of capacity in the Feb. 23 Third Incremental Auction for 2015/16 (ER15-738).
In the second, PJM proposed revising its Tariff to allow it to enter into capacity agreements made outside the Reliability Pricing Model auctions (ER15-739).
Officials told the MRC they would seek to forestall some of the estimated 9,500 MW of retirements expected next year as a result of the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) and more than 2,000 MW being shut down by New Jersey’s High Energy Demand Day regulations.
In addition to offering reliability-must-run (RMR) compensation to delay retirements, officials said they are considering incentives to encourage some generation slated to come on line in delivery year 2016/17 to accelerate construction and launch earlier. In total, officials said they will attempt to secure as much as 2,500 MW of generation through April 2016.
In a related matter, PJM released its 2015 load forecast report. It includes a 2.6% reduction in the load forecast for 2018, due in part to a temporary change in modeling that aims to address over-forecasting in recent years. (See Model Change Results in Lower Load Forecast for PJM.)
The big news of 2014 in PJM was the same subject that’s likely to be big news in 2015: the capacity market.
Of RTO Insider’s 25 most-read stories of 2014, seven were about PJM capacity market rule changes or the results of the May Base Residual Auction.
With PJM seeking to overhaul the market with its Capacity Performance proposal — now pending before the Federal Energy Regulatory Commission — capacity issues are sure to be among the top stories for RTO Insider in the coming year. (See PJM Files Capacity Performance Plan.)
Speaking of FERC, four stories about FERC enforcement and commissioner confirmations also ranked in the top 25. The dynamics of the five-member commission will be fascinating to watch in 2015, with the arrival of new commissioner Colette Honorable and Chairman Cheryl LaFleur and Commissioner Norman Bay swapping seats in April. (See stories No. 2 and No. 18 below.)
DR, M&A, EPA
Demand response, mergers and acquisitions, Environmental Protection Agency regulations and the Artificial Island stability fix each claimed two spots on the list.
The EPA will be the subject of much coverage this year as its Mercury and Air Toxics Standards (MATS) force thousands of megawatts of coal-fired generation into retirement, and as it finalizes its carbon emissions rule in June. Legal challenges to the rule, which have already begun, will surely increase traffic at the D.C. Circuit Court of Appeals.
It was that court that roiled the demand response industry last year with a ruling voiding FERC jurisdiction over pricing of DR in wholesale energy markets, a decision FERC is hoping the Supreme Court will reconsider. (See related story, FERC Report Shows Spotty Growth for DR, Advanced Meters.)
The mergers and acquisitions that were big news in 2014 also will generate headlines this year as they make their way through the regulatory approval process. Among the most prominent: PPL’s spin-off of its generation in a combination with Riverstone Holdings; Exelon’s purchase of Pepco Holdings Inc.; Wisconsin Energy’s acquisition of Integrys Energy Group (with Exelon taking on Integrys’ retail power and gas subsidiary); Dynegy’s acquisition of generation from Duke Energy and Energy Capital Partners; and Constellation combining its commercial and industrial demand response business with Comverge.
PJM had hoped that the selection of a transmission developer for the Artificial Island fix — its first competitive transmission project under FERC Order 1000 — would be completed last summer. But controversy over PJM planners’ selection of Public Service Electric and Gas led the PJM Board of Managers to reopen the bidding for four finalists. Planners hope to present a final recommendation to the Transmission Expansion Advisory Committee in a few weeks. (See PSEG Nuclear Calls on PJM Board to Block ‘Risky’ Artificial Island Fix.)
RTO Insider’s Expansion
While we’ll be writing about a lot of the same issues in 2015, we’ll be doing so with an expanded reporting staff and geographic focus as we deepen our coverage in MISO, SPP, NYISO and ISO-NE.
With this issue, we are expanding our state briefs column to include the 11 MISO states not shared with PJM. Welcome to Arkansas, Louisiana, Mississippi, Missouri, Texas, Iowa, Minnesota, Montana, Wisconsin and the Dakotas — both of them!
Ten of those states are also shared by SPP. We’ll be adding the four states in the rest of SPP’s footprint, along with New York and the states in ISO-NE, later this year.
Welcome to Cruthirds Report Readers
We’ll be doing it with a much larger audience, thanks to our agreement to supply the unexpired subscriptions of The Cruthirds Report. Sadly, The Cruthirds Report ceased operations in December after 11 years of covering Entergy, Southern Co. and the electric industry in the Southeast.
Happily, its founder, former Dynegy regulatory attorney David L. Cruthirds, has agreed to continue raising hell with his observations as a columnist for RTO Insider. You’ll see his introductory column on page 1 of today’s issue.
David also will be writing from the Louisiana Public Service Commission’s monthly Business & Executive meeting in Baton Rouge on Jan. 21 and the Gulf Coast Power Association’s one-day briefing on “Challenges & Changes in Energy on the Bayou” in New Orleans on Feb. 5. The GCPA event will include a discussion on how the MISO South market has worked in the first year and what challenges lie ahead.
David is an outspoken advocate for competition, fairness and transparency. You may not agree with David’s opinions, but you’ll never have a question about where he stands.
We are thrilled to add David’s voice and loyal readers as we continue to build RTO Insider as your eyes and ears in the organized electric markets. Whether it happens in Valley Forge, Washington, Albany or Carmel — RTO Insider will be there bringing you exclusive “in the room” coverage.
Thanks for your support in 2014. Here’s to a great 2015!
The Federal Energy Regulatory Commission Friday rejected a challenge by New England states to recalculate the contributions of demand response and distributed resources in advance of February’s Forward Capacity Auction.
FERC accepted the installed capacity requirement (ICR) filed by ISO-NE for the 2018/19 delivery year (ER15-325). However, FERC did order the RTO to conduct a stakeholder process to develop market rules that would consider DR in time for the 2016 FCA.
The New England States Committee on Electricity said ISO-NE has underestimated the impact of distributed generation and its pay-for-performance (PFP) program on the region’s capacity needs. FERC disagreed.
“We agree with ISO-NE that it would have no basis to use forecasted performance data in the absence of actual historical performance under this nascent two-settlement market design. We therefore support ISO-NE’s current methodology, which incorporates actual resource performance data,” FERC said.
FERC also suggested that a request to include distributed generation as part of the calculation was too soon, saying that the RTO first “must examine the market and operational issues.”
ISO-NE’s Nov. 4 filing established its ICR, local sourcing requirements and Hydro-Quebec interconnection capability credits (HQICC) for FCA 9.
The ISO proposed an ICR value of 35,142 MW, which includes 1,970 MW of emergency generation assumed obtainable from New Brunswick, New York and Quebec. The net amount of capacity to be purchased, after deducting the HQICC value of 953 MW per month, is 34,189 MW, the ISO said.
