The Federal Energy Regulatory Commission last week approved rule changes allowing New England grid operators to fully integrate demand response into their wholesale markets, including their reserve markets (ER15-257).
The changes were proposed by ISO-NE and the New England Power Pool to bring their rules into conformance with FERC Order 745.
Some changes became effective on Jan. 12 in advance of the ninth Forward Capacity Auction, scheduled for Feb.2. Others will take hold on June 1, 2017.
FERC turned aside objections from power generators who want any rulings related to Order 745 deferred until a successful challenge to FERC jurisdiction over DR in a federal appeals court is resolved.
The New England Power Generators Association has argued that the D.C. Circuit Court of Appeals ruling in Electric Power Supply Association v. FERC says that FERC lacks jurisdiction to regulate rates for supply-side demand response resources and could extend to the forward capacity and forward reserve markets.
“We find it appropriate at this time to proceed with these market enhancements until further action is taken,” FERC wrote.
In 2011, ISO-NE and NEPOOL proposed a two-stage process to incorporate DR into the wholesale markets. Stage one defined an initial transition period that began in June 2012. Stage two rules were proposed in this docket in October 2014.
ISO-NE currently models a single DR asset that can both reduce its load and inject energy into the electric grid as two separate assets, according to FERC. ISO-NE and NEPOOL say the changes will allow DR to provide operating reserves as other resources without altering the existing co-optimized energy and real-time operating reserves market. “These changes include revisions to demand response resources’ energy market offer parameters to allow such resources to provide 10-minute and/or 30-minute reserves,” FERC said.
NEPGA also said the revisions discriminate against generation resources in the compensation of DR for avoided line losses.
FERC rejected that argument, saying that “under a common market structure, all resources will have comparable obligations and be paid the comparable price for delivery.”
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.)
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).
