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.)
Greetings. I’d like to say hello to long-time readers from The Cruthirds Report and introduce myself to RTO Insider’s readers and subscribers. After 11 years of writing and reporting on regulatory issues in the Southeast and Midwest for The Cruthirds Report, I decided to suspend operations and start a new chapter of my career.
I will be writing periodic articles and columns for RTO Insider during my transition, and I look forward to sharing news, insights and observations about noteworthy industry developments with RTO Insider’s readers. I appreciate Rich Heidorn Jr. for providing me with this opportunity, and encourage readers to provide feedback and engage in dialogue on anything they see in one of my columns.
Seams, Anti-Trust Practices and Boondoggles
I’ve written extensively on issues such as the costly seams dispute between MISO and its neighbors that include SPP, the Tennessee Valley Authority and Southern Co. The power flows across MISO’s neighbors were clearly foreseeable from the December 2013 integration of Entergy into MISO, but MISO overplayed its hand by relying on a provision in the MISO-SPP joint operating agreement rather than negotiating a new agreement during the two-year Entergy integration process.
I’ve also commented on the U.S. Department of Justice’s still unresolved investigation of Entergy’s transmission and power procurement practices that decimated the merchant power sector in its region.
Other important and ongoing issues of note include Southern’s colossal disaster at the Kemper integrated gasification combined-cycle (IGCC) project in Mississippi. Southern used its political machine to force the project through the Mississippi Public Service Commission despite clear indications that low natural gas prices from the “shale gale” would make the project extremely uneconomic compared to other alternatives. Southern exacerbated the harm to Mississippi Power’s ratepayers and its own stockholders by seriously mismanaging the engineering, procurement and construction aspects of the project, which is based on Southern’s proprietary IGCC technology. So much for utility self-build projects having less risk than market alternatives!
Write it Big & Tall – Or Not at All
As you can see, I’m not shy about taking on controversial issues in my role as an “equal opportunity critic.” My writing style recalls a line from a song by Austin-based singer-songwriter Bob Schneider, who said to “write it big and tall — or not at all.”
Our industry is the lifeblood of our nation’s economy. Life as we know it literally would not be possible without the electric utility industry. Industrial, commercial and residential consumers collectively pay billions of dollars to cover the cost of utility investments and state and federal regulators’ decisions – some good, some not so bad and some really bad ones – so these issues are extremely important and worthy of critical analysis and commentary.
I look forward to contributing to RTO Insider and welcome feedback from readers – on or off the record.
PJM and its Transmission Owners filed a 65-page response Dec. 23 to address what the Federal Energy Regulatory Commission deemed deficiencies in their plan to integrate multi-driver projects into the regional transmission expansion plan (RTEP) (ER14-2864, ER14-2867).
PJM proposed the concept in response to FERC Order 1000, saying it could lower the cost of states’ public policy transmission projects by incorporating them in upgrades that address market efficiency or reliability.
Related revisions to PJM’s Operating Agreement and Tariff were approved by the Members Committee June 26 and filed with FERC Sept. 12, following much debate among stakeholders over what would qualify as such a project and who would pay for it. Some critics worried that the cost allocation scheme would make public policy projects too costly to pursue. (See States Still Miffed with TOs’ ‘Multi-Driver’ Cost.)
FERC’s deficiency notice focused on definitions, process and cost allocation.
Responding to FERC’s question of how such projects will be selected, PJM said, “In essence, there is no separate process for selection of multi-driver projects. … Consistent with Order No. 1000, all projects selected as multi-driver projects will be included in the RTEP for cost allocation purposes because they are found to be the more efficient or cost-effective solution to the PJM region’s needs.”
FERC had also asked PJM and the TOs to show how their cost allocation method satisfied the six regional allocation principles and how it is consistent with determining that participant funding cannot be the regional method.
PJM responded that a multi-driver project will be eligible for regional cost allocation because each component — economic, reliability and public policy — will meet the relevant requirements.
The TOs said that the costs would be allocated “to those who benefit from the facilities in a manner that is at least roughly commensurate with the estimated benefits.”
No new cost allocation method is being proposed for multi-driver projects, the TOs said, with the exception of local transmission projects “boosted” into regional cost allocation due to their combination with a public policy driver. For “boosted projects,” the portion of the project designed for reliability or market efficiency will be allocated 20% pro rata and 80% to those calculated to directly benefit, rather than 50-50.
“Even though the allocation to the reliability or market efficiency portion has changed by having 20% of those portions allocated pro rata, those who would not have received a cost allocation but for the ‘boosting’ of the project to a regional facility, still receive a benefit because of the greater capacity of the regional facility,” the TOs said.
Cost allocation would continue to be assigned by two methods: incremental and proportional.
The incremental method would be used when the project was developed to address a single driver, but modified to satisfy other goals and becomes more cost-effective for all drivers. The initial driver would have its cost share reduced by “an amount equal to the ratio of the estimated incremental cost of the new driver(s) to the estimated new total cost of the project multiplied by the estimated cost of the original driver.”
The proportional method would apply when a project was developed parallel to individual solutions to different drivers and then combined. In that case, cost would be allocated relative to what would have been required to address each driver separately.
Annual Cost Allocation Update Filed
In a related matter, PJM on Dec. 30 submitted its updated annual cost allocation for regional facilities and “necessary” lower-voltage facilities included in the RTEP (ER15-758).
A dozen House Republicans asked the Federal Trade Commission to explore allegations of deceptive trade practices related to third-party solar leases.
Rep. Paul Gosar, R-Ariz., leading the effort, wrote a letter to FTC Chairwoman Edith Ramirez urging the commission to investigate “deceptive marketing strategies” that overpromise the benefits of home solar while understating the risks of entering into an agreement “that will likely exceed both the life of the roof and the duration of the lessor’s home ownership.” He characterized the booming third-party solar installation industry as “largely unregulated.”
“My letter to Chairwoman Ramirez simply asks the FTC to look into these practices and answer a series of questions,” Gosar said in a news release. “In order to protect consumers and expand domestic solar production, proper oversight of the emerging rooftop solar industry must be maintained.”
FERC Approves Cheniere’s Corpus Christi LNG Terminal
The Federal Energy Regulatory Commission last week approved Cheniere Energy’s planned liquefied natural gas terminal in Corpus Christi, Texas. The company now needs only approval from the Department of Energy to start construction.
Cheniere is the only company in the U.S. to have two active LNG export terminal projects underway. Its $10 billion Sabine Pass terminal in Louisiana is already under construction and scheduled to go into operation later this year. Construction at the Corpus Christi terminal should start this year, with an operational date of 2018.
Environmental Groups Charge FERC Erred in Approving NY Pipeline
Environmental groups are asking the Federal Energy Regulatory Commission to reconsider its December approval of the Constitution Pipeline, a proposed 124-mile natural gas pipeline that would run from Pennsylvania into New York.
The groups, including EarthJustice, the Clean Air Council and the Sierra Club, said FERC’s environmental review didn’t take into account habitat damage and runoff potential. “When the Federal Energy Regulatory Commission issues a permit for a natural gas pipeline without fully assessing the environmental impact as required, concerned citizens must take a stand,” said Moneen Nasmith, an EarthJustice attorney.
Stephen G. Burns became the chairman of the Nuclear Regulatory Commission on Jan. 1, assuming the seat held by Allison Macfarlane, who left to take a professorship at George Washington University.
Burns, the commission’s former general counsel, has held various positions at the NRC for more than 33 years, but he has only been a commissioner since November.
Duke Energy’s Dry Cask Storage Plan for Crystal River OK’d
The Nuclear Regulatory Commission has approved Duke Energy’s plan to use dry cask storage for spent fuel at its Crystal River Nuclear Plant in Florida.
Duke ordered the plant permanently shut down in 2013 after its previous owner, Progress Energy, botched repairs in 2009. The company estimates it will cost more than $265 million to build the fuel storage facility. The spent fuel rods are scheduled to be transferred in 2019.
Republicans Asking FERC Commissioners About EPA Meetings on Clean Power Plan
Ranking House and Senate Republicans have asked each member of the Federal Energy Regulatory Commission to describe any meetings they had with the Environmental Protection Agency about the agency’s proposed Clean Energy Plan. The lawmakers suggest that commissioners had little interaction with the EPA before the agency released its new emissions standards. EPA officials have said there was sharing of information.
“Your views about the extent of collaboration between FERC and EPA on these matters, and especially about the details of your personal involvement or that of your staff in any or all of these meetings … will contribute significantly to the public record,” the legislators said in a letter.
It was signed by Sen. Lisa Murkowski (R-Alaska), ranking Republican on the Senate Energy and Natural Resources Committee, Rep. Fred Upton (R-Mich.), chairman of the House Energy and Commerce Committee, and Rep. Ed Whitfield (R-Ky.), chairman of the Energy and Power Subcommittee.
Comment Period on Offshore Wind in Virginia Extended 2 More Weeks
The Bureau of Ocean Energy Management has given a two-week extension for public comment on a pilot project to install two offshore wind turbines in Virginia.
The agency recently issued a 210-page environmental assessment on Dominion Virginia Power’s plan to install two 600-foot turbines and a sea-to-shore transmission line that would set the stage for a more ambitious offshore wind project. The deadline for comment is now Jan. 16.
The Federal Energy Regulatory Commission announced yesterday that Colette Honorable has been sworn in as the commission’s fifth member, replacing former Commissioner John Norris. Honorable, former chairman of the Arkansas Public Service Commission and president of the National Association of Regulatory Utility Commissioners, was confirmed to the position by the Senate in December.
FERC Schedules Workshop on NERC ATC Rules
The staff of the Federal Energy Regulatory Commission will conduct a workshop March 5 to discuss actions the commission may take to ensure that transmission providers are calculating available transfer capability (ATC) “in a manner that ensures nondiscriminatory access” to the grid.
FERC’s action (AD15-5) is a response to the North American Electric Reliability Corp.’s proposed changes to its ATC-related reliability standards and an initiative to replace them with business practice standards to be developed by the North American Energy Standards Board. The workshop will be held from 8:45 a.m. to 5 p.m. in the Commission Meeting Room, 888 First Street NE, Washington, D.C., 20426.
MISO and reliability watchdogs have reached a settlement over self-reported violations related to MISO’s ability to maintain visibility over its reliability coordinator area following a contingency event.
The settlement, between MISO and regional entity ReliabilityFirst, was submitted to the Federal Energy Regulatory Commission Dec. 30 by the North American Electric Reliability Corp. (NP15-14). While MISO will not pay a financial penalty, it agreed to corrective actions.
MISO said it discovered in March 2012 that some of the input data it used in the network model to support real-time analysis of its transmission system was incorrect: for 321 of 19,936 facilities (1.6%), default facility ratings, instead of actual facility ratings, were assigned.
MISO also identified errors in voltage monitoring flags for several facilities and that several transmission lines had monitoring disabled. In addition, alarms on six tie lines were not functioning and the network model failed to monitor 14 transformers.
Another violation resulted from MISO’s discovery that it had only limited ability to determine current post-contingency element conditions (voltage or thermal) within its reliability coordinator area for almost six hours on Jan. 30, 2013.
The problem occurred when a MISO Energy Management System shift engineer implemented a corrupted contingency case file, resulting in 2,626 contingencies being excluded from the real-time contingency analysis database. MISO typically screens for about 11,400 active contingencies.
Alarms Not Heard
“Although MISO has audible alarming to alert control room personnel to significant changes in the number of contingencies in the real-time contingency analysis database, the control room personnel failed to notice the alarm due to other audible alarms sounding at the same time,” NERC said.
The problem was discovered after a transmission operator notified MISO of a trip on one of its transmission lines resulting in new post-contingency overloads on several 69-kV lines.
The settlement resolves violations related to MISO’s operations in the ReliabilityFirst, Midwest Reliability Organization and SERC Reliability Corp. regions.
The regions said the violations did not affect MISO’s processes to identify and validate System Operating Limits (SOLs) and Interconnection Reliability Operating Limits (IROLs), respond to real-time system conditions, or produce next-day models. “Considered as a whole, the regions determined these violations posed a minimal risk to the reliability of the bulk power system,” NERC said.
Penalty Recovery Sought
In a related matter, MISO last week asked FERC for authority to recover from its members a $75,000 penalty arising from a settlement agreement with ReliabilityFirst over earlier reliability violations (ER15-764). The settlement, which was previously approved by FERC, resulted from a compliance audit conducted in late 2012.
MISO and three power suppliers have asked the Federal Energy Regulatory Commission to deny Duke Energy’s request for a waiver from MISO’s must-offer requirement, arguing the RTO’s reserve margins in Zone 6 have fallen by a “dramatic” amount since Indianapolis Power & Light obtained a waiver in October.
Duke Energy Indiana is the latest utility to seek a must-offer waiver (ER15-592), joining others that complain there’s no clear mechanism within MISO’s Tariff that would permit them to buy replacement capacity to cover a six-week gap in 2016 between when they plan to retire coal units under the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) and the end of the MISO planning year on May 31.
Requests by DTE Electric (ER15-90) and MidAmerican Energy (ER15-199) are pending before the commission. Consumers Energy, having been denied a waiver request last fall (ER14-2622), has come back to the commission with a modified request (ER15-435).
Duke told the commission that buying replacement capacity for its Wabash Units 2-6 for the six-week period could cost up to $17.7 million. Consumers said buying replacement power for the 2015-2016 planning year would cost $5.8 million to $84.8 million.
In a Dec. 29 filing opposing Duke’s request, MISO said the waiver requests have grown to 2,440 MW.
“It is very difficult to understand how these accumulated waiver requests are limited in scope and will not have a great potential for undesirable consequences. Moreover, a large number of pending requests creates additional regulatory uncertainty among buyers and sellers of capacity and hinders the efficiency of MISO’s capacity construct,” MISO said.
Dynegy, NRG Energy and Exelon also opposed Duke’s request, arguing that MISO’s reserve margins have suffered a “dramatic” fall since IPL’s June 2014 request. IPL cited an “available maintenance” of a minimum 3,000 MW in Zone 6 for the April-May 2016 period.
“By contrast, [Duke Indiana] acknowledges that ‘MISO’s updated monthly Maintenance Margins’ now show a low of 738 MW,’” the companies said in a Dec. 29 protest. “This is a razor-thin margin in a zone with forecasted demand of 17,629 MW.”
Bay warned that a one-time waiver “creates an unfortunate precedent that erodes MISO’s capacity construct, undermines the bilateral market for capacity and blurs, unnecessarily, a line that had once been bright.”
MISO used a monthly resource adequacy construct until 2012, when the RTO won FERC approval for an annual construct, saying the monthly capacity products might not provide the certainty to attract competitive participants to the auction. The change meant that capacity resources would be required to be available anytime during the planning year.
That became problematic when utilities began making plans to retire older units to comply with MATS. Duke Indiana decided that in 2016 it would retire Wabash Units 2-5 and suspend Unit 6.
Duke argues that it essentially faces the same situation that confronted IPL, which plans to retire its Eagle Valley coal units in 2016 as part of MATS compliance.
Duke Leaves Bigger Void
But suppliers noted that Duke’s 668-MW Wabash units are considerably larger than Eagle Valley’s 216-MW capacity.
In November, the commission rejected Consumers Energy’s initial request for a waiver of its Classic Seven units, noting they comprise 940.7 MW in Michigan, 14.5% of the utility’s total capacity.
As for Duke’s must-offer waiver request, the three suppliers told FERC that while the Eagle Valley plant represents about 1.2% of total demand forecast for MISO’s Zone 6, the combination of Eagle Valley and Wabash River Units 2-6 “would now represent 5% of the total demand forecast in that zone.”
Demand response and advanced meters are continuing to grow but progress is uneven, with some regions showing reductions in DR even before last May’s appellate court ruling challenging federal jurisdiction over the resource, according to a new report by the Federal Energy Regulatory Commission.
Nationally, potential peak reduction from DR in the organized markets grew 9.3%, or 2,451 MW, to 28,503 MW from 2012 to 2013. Potential peak reduction in RTOs and ISOs grew to 6.1% of peak demand in 2013, from 5.6% in 2012.
This occurred despite some setbacks in Northeastern markets, according to the ninth annual Assessment of Demand Response and Advanced Metering report released Dec. 23.
FERC also reported that advanced meters now represent almost 30% of the total, as an additional 5.9 million devices were deployed between 2011 and 2012.
Demand Response in RTOs, ISOs
Potential peak reduction increased by 2,600 MW in MISO from 2012 to 2013, largely due to increased demand response from behind-the-meter generation and load-modifying resource programs run by utilities.
In NYISO, however, fewer DR resources registered as special case resources following the RTO’s implementation of its baseline calculation and auditing methods, according to FERC. Tighter qualification criteria may have played a role. Relatively low capacity prices in NYISO were also cited.
DR in ISO-NE declined by 669 MW, or 25%. FERC cited reports that EnerNOC had reduced its participation in the forward capacity market because its customers believe that participation requirements outweighed the benefits.
DR’s future was further clouded by the D.C. Circuit Court of Appeals’ ruling, in a challenge by the Electric Power Supply Association, voiding FERC’s jurisdiction over pricing of DR in wholesale energy markets. FERC is seeking a Supreme Court review of the ruling.
Despite the legal uncertainties, demand response continued to prove its worth last year as a tool for grid operators during times of tight supplies, FERC observed. PJM activated about 2,000 MW of DR for several hours on Jan. 7, 2014 and more than 2,500 MW for several hours on Jan. 23 and Jan. 28.
ISO-NE’s 2013-2014 Winter Reliability Program gave it the ability to call on DR up to 10 times during the winter. DR resources provided 21 MW on each of five occasions between December 2013 and February 2014, according to the report.
Advanced Meters
Advanced meters continued to grow, but penetration rates varied widely by region.
The Texas Regional Entity leads, with penetration of 70%, followed by the Western Electric Coordinating Council at 51%. Bringing up the rear are ReliabilityFirst, which includes portions of PJM and MISO, at 17%, and the Northeast Power Coordinating Council at 12%.
Among the capabilities of advanced meters is time-based pricing. But the report found that enrollment in time-based DR programs dropped by 6.1% between 2011 and 2012.
FERC said participation dropped in SPP due to the end of programs by Southwestern Electric Power Co. and a large decline in enrollment in the programs run by Public Service Company of Oklahoma. The ReliabilityFirst region saw a decline as a result of attrition in Ohio Power’s residential program and Duke Energy Indiana’s commercial program.
Two of the world’s largest wind farms have joined a complaint against Northern Indiana Public Service Co., asking the Federal Energy Regulatory Commission to cut the $35.8 million bill the utility assessed them and others in connection with transmission upgrades needed to reduce congestion that has caused frequent curtailments.
NIPSCO charged Fowler Ridge, Meadow Lake and seven other wind farms $50.4 million to build the upgrades and an additional $35.8 million to operate them over 35 years.
FERC ruled Dec. 8 that the 1.71 multiplier NIPSCO used to calculate the operating costs is too high. But it denied a request by the original complainant, E.ON Climate and Renewables North America, to eliminate it entirely. Instead, it directed NIPSCO and E.ON to enter settlement proceedings to determine a fairer rate (EL14-66).
The owners of the Fowler Ridge and Meadow Lake wind farms, located in western Indiana, filed their complaint last week (EL15-34), saying they wanted to ensure they would share in any refunds resulting from the resolution of the E.ON case.
Fowler Ridge and Meadow Lake companies were part of a group of Indiana wind farm owners that negotiated last year with NIPSCO a transmission upgrade agreement to alleviate congestion on the utility’s system.
E.ON estimated its Pioneer Trail and Settlers Trail wind farms, with 300 MW of combined capacity, lost between $9.8 million and $11.7 million in 2013 when grid operators forced them to curtail their output due to congestion.
Because MISO’s Tariff does not include a procedure for calculating the cost of transmission upgrades that require customer funding, the RTO instructed the wind companies to deal with NIPSCO directly.
E.ON said it immediately objected to the operating cost multiplier but that both MISO and NIPSCO refused to file the agreement on an unexecuted basis — an action that would have allowed FERC to rule on it before it went into effect. NIPSCO also refused to go through with the upgrades unless E.ON and the other companies signed the agreement and paid the total cost upfront, E.ON said.
“[G]iven the continuing curtailments, the only avenue was to agree to the terms of the proposed” agreement and hope that FERC would find it unjust once it was filed in February 2014, E.On said. FERC accepted the agreement in late March, and E.ON filed its complaint in June.
The 600-MW Fowler Ridge, jointly owned by BP Wind Energy North America and Dominion Resources, and the 526-MW Meadow Lake, owned by EDP Renewables North America, rank among the largest wind farms in installed capacity. Collectively they make up 73% of Indiana’s total wind capacity, according the U.S. Department of Energy.
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.
