Fitch Ratings affirmed SPP’s long-term debt rating at A (third-highest) and its short-term grade at a top-ranked F1. Fitch said approximately $267 million of SPP debt was affected by the rating action, which came with a stable rating outlook.
Fitch said the ratings reflect SPP’s predictable cash flows as a result of its FERC-approved Tariff, which provides for the full recovery of all costs. It also cited the low business risk of its transmission operations, the investment-grade credit worthiness of its members and FERC’s “supportive federal regulatory environment.”
Fitch found SPP’s current liquidity position to be “sufficient,” with a $30 million unsecured revolving line of credit and approximately $43 million of unrestricted cash and cash equivalents.
Fitch said SPP’s voluntary membership remains “a modest credit concern,” which is mitigated by exit fees “equal to its share of SPP’s outstanding debt and other committed expenses.” Fitch also noted SPP’s exposure to a market participant’s payment default “is minimized by the collateral requirements as well as bylaws that allow for costs of the default to be spread among the remaining market participants.”
CAMBRIDGE, Mass. — Officials from PJM and ISO-NE were joined by consultants and market players in debating new performance incentives and the pros and cons of energy-only scarcity pricing at EUCI’s Capacity Market conference early this month. Several employees of MISO, which runs a voluntary capacity market to supplement state resource planning, were in attendance.
Below are some of the highlights.
PJM Senior Economic Policy Advisor Paul Sotkiewicz said he wishes consultant Roy Shanker had never invented the term “missing money” in describing the need for a capacity market.
“It makes it sound like it’s only about money when really this is about reliability,” he said. Capacity is less than 20% of wholesale cost, “yet we fight some of the biggest holy wars over it,” he added.
One of the benefits of PJM’s Reliability Pricing Model for capacity is that it is technology-, size- and age-neutral, he said. “I don’t care if you put a hamster on a wheel. As long as you feed it lettuce and it runs, [PJM is] good with it.”
Michael Borgatti, director of RTO Services for Gabel Associates, said PJM’s Capacity Performance rules are more risky for generators than ISO-NE’s Pay-for-Performance.
Borgatti said PJM officials have said that their limited force majeure rules would not have been declared in either the derecho or Hurricane Sandy in 2012.
“We can show you the material where they tell you you would have been penalized, even though the transmission lines are laying on the ground,” he said. “Now if the dispatcher calls you and says ‘the transmission lines are laying on the ground, take your machine offline or you’re going to blow a substation,’ you’re [absolved of] penalties. So this is the subjective nature of the PJM package. I would not count on simply the fact that the transmission system failed to excuse you from penalties.”
William Hogan, research director of the Harvard Electricity Policy Group, said the new capacity rules in ISO-NE and PJM have worsened the “disconnect” between the energy and capacity markets.
“I understand the problem and I think trying to make sure the generators perform is a good idea. But I think this is a Rube Goldberg system designed to avoid the obvious,” he said. “It does capture the marginal incentives for the generators … but it completely excludes load from this conversation.”
PJM Market Monitor Joe Bowring responded to Hogan’s criticism of PJM’s capacity construct, acknowledging that other markets have gone different routes in ensuring resource adequacy: Alberta allows limited market power; MISO uses cost-of-service regulation; California uses bilateral contracts; and ERCOT uses scarcity pricing.
“But all of these solutions have one element or another of administrative oversight,” Bowring said. “That is, none of them are some pure market solution.”
Sam Newell, principal for The Brattle Group, noted that his company has been involved in the calculations of the cost of new entry (CONE), which are used to set the ceiling on capacity offers. PJM allows bids up to 85% of net CONE without review.
“The thing that makes me nervous is that we’ve been involved many times in determining what is net CONE for use in the auction. I think we do a great job of it. But I know better than anybody there’s a lot of uncertainty in it. So, in effect, this very big administrative parameter, net CONE, now takes on a lot more weight. But I don’t know if it’s that’s the right level.”
Jeff Bentz, director of analysis for the New England States Committee on Electricity, said the joint solicitation for clean energy resources by Massachusetts, Rhode Island and Connecticut was a response to the lack of progress on proposals to bring new transmission into the region. (See New England States Combine on Clean Energy Procurement.)
“The concept here is we would hope maybe a wind provider and a solar provider and a hydro provider could maybe team up as one bidder and team up with a transmission developer and builder, and those three or four entities could put one bid into the RFP. And then when the wind’s blowing, the wind guy is providing the clean energy commitment. When the wind’s not blowing or the sun’s not out, the hydro guy can step in and fill the line. So we kind of wanted to leave this up to the market and let them prescribe how they best can meet the delivery commitment.
“[I have] no idea whether this is going to work or not. No idea whether the bids are going to be beneficial or not. But on the other hand we don’t see anything else really coming in to New England to solve this infrastructure issue.”
Andrew Gillespie, principal analyst for ISO-NE, said he hopes Pay-for-Performance will reduce the use of administrative pricing in future auctions. But he said they are unlikely to be eliminated because of political opposition to severe short-term price spikes.
“You could have price signals that in the long run provide the most efficient outcomes, but we don’t live in the long run,” he said. “The political reality is we live in the here and now. It is untenable to consumers for prices to go to $17, $18/kWh.”
Scott Harvey of FTI Consulting said that forward capacity markets such as PJM’s make procurement decisions based on often incorrect RTO load forecasts. “We’re consistently over-forecasting demand. So we’re constantly buying too much capacity. That’s one of the consequences of contracting forward like this.”
Todd Schatzki, vice president at the Analysis Group, said his company’s research has found wide disparities between the best- and worst-performing generators during reserve shortages. That, he said, will be reflected in their offers into the PJM and ISO-NE markets.
“If I’m a good resource, I actually want to be in this market. This is a good market for me because I’m going to make more money when I get to the compliance period. If I’m a poor resource, I’m probably going to lose money when I get to the compliance period, but I’m going to be able to anticipate that and include that in my offer.”
Debate over PJM Transition Auction
Wilson
PJM’s 2016/17 transition auction results were released during the conference, sparking a debate between Sotkiewicz and James Wilson, a consultant to consumer advocates in the RTO. (See Timing of PJM Auction Announcement Sparks Real-Time Debate.)
BOSTON – ISO-NE’s draft Regional System Plan shows flat load growth through 2024 due to growing solar PV and energy efficiency but predicts challenges from generation retirements and integration of variable resources.
The plan, released at a presentation last week, also cites eastern Massachusetts and Rhode Island as having the greatest need for new generation.
Load is growing annually at about 1.3%, said Michael Henderson, director, regional planning and coordination for ISO-NE. “But you subtract photovoltaics and energy efficiency, it comes down to about 0.6%,” he said.
The net summer peak average forecast is 26,565 MW for 2015, which grows to 27,875 MW for 2024. Winter load is slowly growing, but that peak is at night, when PV is of no help.
‘Tremendous’ Renewable Potential
The study says the region has “tremendous potential” for renewable energy, but it requires additional transmission, revisions to interconnection requirements and improved forecasting to ease their integration.
The region had 908 MW of solar capacity (nameplate rating) at the end of 2014, which is expected to grow to 2,449 MW over the next decade.
“As these [interconnection] improvements are made, it can only act to promote distributed resources because they will then be interconnected in a more reliable way and the overall system will be more tolerant of distributed resources,” Henderson said.
The region has almost 2,000 MW of wind capacity with another 4,100 MW in the interconnection queue. “Proposed onshore wind resources are predominantly in northern New England, and offshore resources are being proposed off the southeastern New England coast,” the study says. “A number of wind projects have interconnected to areas of the regional power system that have favorable wind conditions but are electrically remote and weak, and additional wind projects are proposed for these areas.”
Capacity Additions
A bright spot is the additional generation resources attracted in the ninth Forward Capacity Auction. (See Exelon, LS Power Join CPV in Adding New England Capacity.) The report cites improved incentives for resource performance and the use of a sloped system demand curve in the Forward Capacity Auctions to reduce price volatility.
“The addition of natural gas pipeline capacity or the increased use of existing [liquefied natural gas] facilities also could improve fuel assurance and regional reliability,” the study says.
The plan reiterates previous concerns about the north-south transmission corridor that starts north of Boston and runs through the metropolitan area into Rhode Island. New resources in the NEMA/SEMA/RI areas would provide the greatest reliability benefit.
Interregional Planning
The study calls for increased coordination of planning with other systems “particularly to provide access to a greater diversity of resources, including hydro and variable resources, and to meet environmental compliance obligations.”
The Operating Committee last week unanimously agreed to create a task force to close the gap between PJM metering requirements and member practices.
The Metering and Metering Requirements Task Force will be tasked with revising Manual 1: Control Center and Data Exchange Requirements.
“Manual 1 is deserving of a rewrite; it’s been too long,” PJM’s Ryan Nice said. “Metering is important because it’s a large capital investment, and it feeds into a lot of settlement applications.”
The changes will aim to address “long-standing clarity and readability issues” that have caused gaps between PJM’s “intended meaning and member understanding” on metering requirements, according to the problem statement.
Among the topics to be considered are meter maintenance and calibration standards. The group will examine existing metering infrastructure and common practices, particularly among transmission owners.
The work is expected to take three to six sessions.
Members should send names of those interested in joining the task force to ryan.nice@pjm.com.
Proposal Would Curtail RegD Resources in Regulation Market
The Regulation Performance Impacts group has proposed a modified benefits factor curve and a situational cap on “RegD” megawatts to address the issue of PJM’s regulation market purchasing too much of the fast-responding resources at times.
The solution, which will be brought up for a vote at the group’s Sept. 25 meeting, involves moving the benefits factor curve to the left so that it is at 0 at 40%. A cap of 26.2% also would be implemented during identified excursion hours — hours when dispatch frequently manually moves the regulation signal.
In addition, the group proposes a “tie-breaker logic” for the benefits factor ranking to address the issue of the adjusted total cost formation being ineffective when RegD self-schedules or is offered at $0.
“We want to review this quarterly,” Hsia said. “Nothing’s etched in stone.”
A federal appeals court panel rejected the first effort of a collection of states to block the Obama administration’s power plant climate rule, deciding the states can’t ask for the plan to be killed before legal challenges are complete.
The D.C. Circuit Court of Appeals issued a two-paragraph order Wednesday evening, ruling that more than a dozen states and a coal company cannot be granted a stay of the Environmental Protection Agency’s Clean Power Plan, which aims to cut carbon emissions by 32% in 15 years.
The panel ruled that legal challenges can only be mounted after the final rule is published in the Federal Register, which is expected in October.
AP Study Finds Waste Spills Follow Oil and Gas Drilling Booms
An Associated Press analysis shows that more than 175 million gallons of wastewater were spilled in more than 21,000 individual incidents at oil and natural gas drilling sites between 2009 and 2014. The report says that even more incidents go unreported.
The wastewater spills can be even more damaging to the environment and agriculture than oil spills. AP reported that in seven of 11 states examined, the amount of wastewater released was at least twice as much as the amount of oil spilled. It said that spilled oil can be absorbed and broken down by microbes, but briny wastewater can be deadly and long lasting to crops, trees and livestock.
“Oil spills may look bad, but we know how to clean them up and … return the land to a productive state,” said Kerry Sublette, a University of Tulsa environmental engineer. “Brine spills are much more difficult.”
The American Petroleum Institute and America’s Natural Gas Alliance, two of the country’s largest oil and gas industry groups, are considering a merger, according to Politico.
The news site says the move may be spurred by the low prices of oil and natural gas, and the feeling by some of the groups’ members that membership in both organizations is costing too much. The story also noted that the positions and strategies of both groups are growing ever closer, especially in the areas of oil exportation and natural gas production in shale-field regions.
API Chief Jack Gerard is one of the lobbying industry’s highest paid members. Federal disclosure forms show he received $13.3 million in compensation in 2013.
NRC Ends Study of Cancer Risks Near Nuclear Plants
The Nuclear Regulatory Commission, citing budget constraints, is ending a National Academy of Sciences study of cancer risks near nuclear generating stations.
“We’re balancing the desire to provide updated answers on cancer risk with our responsibility to use congressionally provided funds as wisely as possible,” said Brian Sheron, director of the NRC’s research office. “The NAS estimates it would be at least the end of the decade before they would possibly have answers for us, and the costs of completing the study were prohibitively high.”
The study was started in 2010, and the first phase was completed in 2012. It consisted of recommendations for the second stage of the study, which was estimated to cost $8 million and could take an additional 10 years.
Poll Finds 73% of Americans Favor Greater Limits on Ozone
A poll commissioned by the American Lung Association has found that 73% of Americans want the Environmental Protection Agency to set stricter limits on ozone pollution. The EPA proposed stricter limits in November that would restrict ozone levels in the air to between 65 parts per billion (ppb) and 70 ppb. The current limit is 75 ppb.
“Millions of Americans are breathing polluted air and suffering from asthma attacks, increased risk of respiratory infections, and even premature death,” said Harold Wimmer, ALA’s national president.
Manufacturing groups oppose changing the limits. “While western states have cut their production of smog-causing ozone by over 20%, studies show that pollution from China has offset much of that progress,” an advertising campaign by the National Association of Manufacturers says. “These rules won’t hurt China, but they could cost our country more than $1 trillion.”
FERC Names Carmen Cintron Administrative Law Judge
Cintron
FERC has named Judge Carmen Cintron as deputy chief administrative law judge. She will assist FERC Chief Administrative Law Judge Curtis Wagner Jr. with the Office of Administrative Law Judges and Dispute Resolution.
Cintron has been with FERC since 1999. She was a hearing-office chief of the Social Security Administration’s Atlanta North Office of Hearings and Appeals, overseeing an office of 11 administrative law judges and a staff of 50. She previously worked as an administrative law judge in the administration’s San Jose, Calif., office. She worked 14 years with the Federal Communications Commission as an attorney before that.
Officials with the federal Bureau of Ocean and Energy Management have identified two areas offshore of South Carolina as possible sites for wind power facilities.
The next step would be an environmental assessment of the sites. One is off Myrtle Beach; the other is off Cape Romain, toward the state’s southernmost area.
Federal officials spoke to members of the South Carolina Renewable Energy Task Force, saying it would probably be seven years before an operating wind farm is anchored off South Carolina’s coast.
SunEdison will pay $300 million for 33% of Dominion Resources’ solar assets, which are rated at 425 MW.
The deal, announced last week, gives SunEdison the option of acquiring the rest of Dominion’s solar portfolio, which includes 24 projects in California, Connecticut, Georgia, Indiana, Tennessee and Utah. Fifteen of the facilities went into service in 2013 or 2014. The rest are scheduled to go into service this year. All have long-term power purchase agreements in place. The agreement needs the approval of FERC.
Dominion CEO Thomas Farrell II said the company is not getting out of the solar business, but is “shifting from constructing contracted solar to constructing utility solar in Virginia, where we expect 400 MW of generating capacity by 2020.”
Energy Storage Market Showing Signs of Record Quarters
The price for energy storage is coming down, with the median price for utility-scale battery systems in the $900/kWh range in the first and second quarters.
GTM Research reported that the low price declined from $800/kWh in the first quarter to $750/kWh in the second. The decline was partly attributed to improvements in energy-storage technology, as well as competitive pressure from Tesla, which announced it aimed to turn out batteries for about $250/kWh.
Meanwhile, battery deployment continues to rise, with 40.7 MW of capacity installed in the second quarter, six times the amount reported in the previous quarter and nine times more than the previous year.
Solar Capacity Hits Record of Almost 1,400 MW Installed
The second quarter of 2015 saw solar power capacity installation of 1,393 MW, pushing the market total to about 20 GW. Most of the new capacity was from utility installations.
Residential solar, too, set a record, with 473 MW being installed in the same quarter, a 70% increase over the same period the year before, according to the Solar Energy Industries Association quarterly market report.
SEIA President Rhone Resch urged government to maintain the momentum by renewing the investment tax credit set to expire next year. “The demand for solar energy is now higher than ever and this report spells out how crucial it is for America to maintain smart, effective, forward-looking public policies, like the ITC, beyond 2016,” he said.
Duke Energy Adds 30 MW of Solar to Fleet, 132 MW more Coming
Duke Energy Renewables reported that it has completed construction of four solar farms in North Carolina, adding 30 MW of capacity to its solar stable. All four facilities are in Eastern North Carolina, and all are under contract to provide their output to Dominion NC Power.
Duke said it has three more facilities — totaling 132 MW — under construction, including one that will produce 80 MW, which it billed as the largest solar project east of the Mississippi.
Duke Energy Renewables already has 105 MW of solar generation in North Carolina.
GE Gets European Regulators’ OK for Alstom Acquisition
European regulators approved General Electric’s $13.5 billion acquisition of the power generation portion of French company Alstom. Regulators said GE had addressed all antitrust concerns. GE wants to use Alstom’s power generation and power grid equipment business to boost its presence in those industries.
GE CEO Jeffrey R. Immelt said the acquisition would bring the company back into the industrial equipment business and away from its previous foray into financing, which is seen as riskier. As a condition of the regulatory approval, GE has agreed to divest some of the Alstom power generation business to Italian company Ansaldo Energia.
Golden Spread’s ‘Beast,’ Gas CTs Supplies SPP, ERCOT Grids
Golden Spread Electric Cooperative last week unveiled the first of three 191-MW natural gas turbines it is constructing at its Antelope Elk Energy Center north of Lubbock, Texas. The site is strategically located at the intersection of two major power grids.
The project incorporates General Electric’s latest 7FA.05 combustion turbines, which can reach 70% capacity within 10 minutes, making them ideal to use in conjunction with the region’s intermittent wind and solar production. Golden Spread is also installing grid-switching equipment that will allow the units to supply power to either SPP or ERCOT, the two electric grids in which Golden Spread serves its 16 distribution cooperative members.
ERCOT CEO Trip Doggett and SPP president and CEO Nick Brown were among those attending the power plant’s debut. Brown applauded Golden Spread for having the vision to construct the Antelope Elk Energy Center at a crossroads between two major power grids, and to embrace a strategy to integrate quick-fire generation technology with renewable energy sources.
Ameren Targets Investments in Illinois over Missouri
After several failed attempts to change Missouri’s utility laws, St. Louis-based Ameren is shifting capital away from Missouri and into federally regulated transmission lines and its electric and natural gas holdings in neighboring Illinois. It says it plans to invest far less into its larger Missouri utility’s infrastructure over the next five years.
Ameren says Missouri’s regulations governing monopoly utilities make the state less attractive for investment. It said Illinois changed its electric utility laws in 2011 to give utilities more certainty during rate cases in the hopes of spurring more investment in electric infrastructure.
Illinois’ framework is similar to the ratemaking process at FERC, which governs transmission lines. Along with a more favorable ratemaking process for utilities, FERC lets them earn a higher return on investment than allowed by state regulators in order to encourage a build out of the electric grid.
Exelon Names Linda P. Jojo to New Seat on Board of Directors
Jojo
Exelon notified the Securities and Exchange Commission that it increased the number of board seats to 14 and that it named airline executive Linda P. Jojo to the new seat effective Sept. 1.
Jojo is chief information officer and executive vice president of United Continental Holdings. She previously held similar positions with United Airlines, Rogers Communications and Energy Future Holdings.
Exelon said she will serve until the 2016 annual meeting. She will serve on the board’s finance and risk committee.
Duke Energy Settles with Feds on 15-Year-Old Clean Air Violations
Duke Energy will pay a penalty of nearly a million dollars and invest $4.4 in environmental mitigation projects to settle charges that it violated clean-air laws 15 years ago by modifying coal-fired generating stations without emissions control equipment.
The proposed settlement was reached with the Environmental Protection Agency and the U.S. Department of Justice. The company has already shut down 11 of the 13 units at the North Carolina coal plants that were cited for violations. The shutdowns become permanent as part of the settlement. Duke must continue to operate emissions control systems and meet emissions limits at the two remaining units at its Allen power plant in Belmont. The settlement calls for the company to retire those units by the end of 2024.
“After many years, we’ve secured a strong resolution, one that will help reduce asthma attacks and other serious illnesses for the people of North Carolina,” said Cynthia Giles, assistant EPA administrator for enforcement.
Westar is planning to build a community solar garden of up to 10 MW and is seeking help in getting it built.
The Kanas utility issued a request for proposals from qualified solar developers. It hasn’t decided yet whether it will be a ground-based or elevated solar facility. It wants the facility to be completed by the end of 2016.
Developers have to file a notice of intent with Westar by Sept. 25 and submit their final proposal by Oct. 19.
SolarCity Signs Hawaiian Utility for Solar, Energy Storage Project
A Hawaiian utility has signed a power purchase agreement with SolarCity to buy stored solar-generated power during the evening, when demand is higher. SolarCity said it is able to generate electricity during the day, store it, and release it during the night.
The 52-MW battery system is joined with a 13-MW solar facility. The Kauai Island Utility Cooperate said the arrangement will make it less reliant on diesel generation, saving money and reducing greenhouse gas emissions.
New SPP Connections Lead Xcel Energy to Offer Refunds to Texas Customers
Xcel Energy is refunding $18.6 million to Texas retail customers in the Panhandle and South Plains, thanks to lower fuel and purchased-power costs that were made possible by new transmission line connections with SPP.
David Hudson, president of Xcel Energy’s Southwestern Public Service, said new transmission lines connecting Xcel with SPP have expanded the purchase of competitively priced power. Xcel’s ability to import from SPP increased from a little more than 400 MW two years ago to as much as 1,700 MW today. In addition, natural gas prices remained very low through the first part of this year.
Texas residential customers using 1,000 kWh/month will see a one-time credit of $34.42, prorated over two billing cycles.
Darren Rainke, Manitoba Hydro’s chief financial officer, has been named interim chief executive officer of the public power company. He will take the place of Scott Thompson, who announced he was stepping down in June to take a position in the private sector.
Rainke will continue to be CFO while the company looks for a permanent chief executive.
Pipeline Company Moves Ahead Without Regulatory Approval
Although it still needs regulatory approval from four states, Energy Transfer Partners is moving ahead with construction preparations for its Dakota Access Pipeline. The Texas company is stockpiling the pipe it will need for the $3.8 billion, 1,130-mile crude oil pipeline. The project is designed to move crude from North Dakota to a terminal in Illinois, from where it will be sent to markets in the East and Southeast.
But it is a gamble. The pipeline still needs approval from North Dakota, South Dakota, Iowa and Illinois. “What the company does is at their own risk,” said North Dakota Public Service Commission Chairwoman Julie Fedorchak.
Energy Transfer Partners has pipeline and other materials stockpiled at storage yards in North Dakota, South Dakota, Illinois and Iowa.
ERCOT’s seasonal assessments of resource adequacy (SARA) for the fall and winter predict enough generation available to serve forecasted peaks.
The Texas grid operator’s fall SARA shows 77,289 MW of generation available this October and November, more than enough to meet its expected peak of 49,709 MW.
According to the preliminary winter SARA, ERCOT will have 78,253 MW available to meet a projected peak demand of 57,400 MW from December through February 2016. A final winter assessment with an updated weather forecast is scheduled for release Nov. 3.
ERCOT said it expects reserves to range from about 3,600 MW — should peak demand be significantly higher than expected — to nearly 15,000 MW under expected conditions.
“We’ve captured a wide range of scenarios,” said ERCOT’s Pete Warnken, manager of resource adequacy, in response to RTO Insider. “Based on our most recent scenarios, we feel very comfortable with our forecasts.”
ERCOT said it will “continue to monitor the potential effect of Texas’ future drought conditions on generation capacity and ongoing changes to environmental regulations.”
850 MW Additional Capacity Online
ERCOT has added 850 MW of installed capacity since its preliminary fall assessment was published in May, thanks to a combined-cycle generator and three wind projects. Another 1,058 MW of wind projects have been delayed beyond Oct. 1, and will no longer contribute to the fall’s expected capacity.
ERCOT senior meteorologist Chris Coleman said he expects average fall weather despite unusual weather patterns associated with warm ocean temperatures.
Coleman said El Niño this year could be the strongest since 1997, leading to colder, wetter and cloudier winter weather. He said it could also lead to more wind power generated. ERCOT generates about 1,000 MW of wind power during the winter and exceeds 4,000 MW during the summer.
The peak forecast is based on normal weather conditions for 2002-2013 during peak maintenance periods.
ERCOT’s all-time winter peak of 57,265 MW, set in February 2011, was nearly matched in January 2014. The 2014 conditions are reflected in the extreme scenarios included in the winter assessment.
One megawatt powers about 500 homes in Texas during mild weather conditions and about 200 homes during summer.
VALLEY FORGE, Pa. — Members debated four potential changes to the $1,000/MWh energy offer cap last week at a specially called meeting of the Markets and Reliability Committee, failing to agree on any one — or even which should be the main and alternate proposals.
Further discussion was deferred until Sept. 24, giving stakeholders only a few weeks to reach consensus before the Board of Managers takes the matter into its own hands before winter.
Supporters of an increase in the cap say it is necessary to ensure that gas-fired generators can recover their costs when fuel prices spike during periods of extreme temperatures, such as the 2014 polar vortex.
Direct Energy had kicked off the latest effort to reach agreement in July with its plan to raise the cap to $2,700/MWh for cost-based day-ahead offers and price-based real-time offers. The number is 50% more than the highest offers reported by PJM last winter. PJM said that it would support the Direct Energy proposal. (See PJM Stakeholders Struggle for Consensus on Offer Cap.)
Joe Wadsworth of Vitol reiterated his concern about potential unintended consequences inherent in applying different rules to the day-ahead and real-time markets. “We could be artificially creating arbitrage opportunities,” he said, adding that such a scenario might invite increased scrutiny from FERC enforcement.
“We need to ensure the day-ahead and real-time market parameters are the same whenever we can,” he said.
Jim Jablonski, of the Public Power Association of New Jersey, said that whatever the proposed offer cap is, it’s critical it be able to be supported by data. “We can’t get to FERC and say, ‘Oh, we just doubled the old one.’”
Jablonski asked Direct Energy’s Jeff Whitehead if he could estimate exactly how much uplift a higher cap might eliminate. “I’d love for somebody to say, ‘This is how much,’” he said.
Whitehead responded, “The higher the offer cap, the less uplift we’ll have.”
Steve Lieberman of ODEC called his plan “the only proposal that was a joint effort of load and supply.”
It would allow cost-based offers of up to $1,800/MWh and allow them to set LMPs.
And, he said, “Old Dominion firmly believes in the need for a cap that is the same in both markets.”
The Monitor’s proposal would allow cost-based offers to exceed $1,000/MWh when a unit’s short-run marginal costs exceed that cap. Price-based offers would have to be less than or equal to such cost-based offers. Monitor Joe Bowring said the approach addresses the issue of market power when the overall market is tight.
The P3 proposal was the only one that had not previously been presented.
In making the presentation, David “Scarp” Scarpignato of Calpine said that because generators have a must-offer requirement to enter into the day-ahead market, it’s essential they be able to recover their costs.
“The uplift method is a bad idea,” he said. “It’s unhedgeable, and there’s extra risks added to load prices. If you don’t put them into LMP, you lose a very important market signal.”
In allowing offers to set LMPs, according to the proposal, higher prices incent generators to perform.
Like Lieberman, Scarp said the day-ahead cap must equal the real-time cap. Under his proposal, cost-based offers for both markets would be capped at cost plus 10%; market-based offers would be capped at the higher of $2,700/MW or the cost-based offer.
The proposal also sets penalty factors of $1,350/MW for synchronized or primary reserves, and $750/MW for excess synchronized or primary reserves.
PJM has reduced the number of potential transmission fixes for the AP South/AEP-DOM constraints to six candidates.
Six other projects were eliminated following sensitivity analyses for changes in load forecasts and fuel prices.
The projects remaining cleared the 1.25 benefit-cost ratio under all sensitivities and also reduced both AP South and AEP-DOM congestion in combined 2019 and 2022 simulations.
The six proposals include three by Dominion Resources and one submitted by Dominion High Voltage Holdings and Transource Energy (itself a partnership of American Electric Power and Great Plains Energy). The finalists also include one project each from LS Power and Duke-American Transmission Co. Costs of the projects range from $25 million to $301 million.
The fuel price sensitivity looked at natural gas costs $1/MMBtu higher and lower than the prices assumed in the base case. The load forecast sensitivity included an increase and decrease of 2% in load.
LS Power’s Sharon Segner questioned the planners’ screening. “There’s nothing that puts any kind of weight on the cost side and cost containment,” she said. LS Power’s $48.6 million proposal includes a cost cap.
Paul McGlynn, PJM general manager of system planning, said planners will consider cost certainty in further pruning the list of finalists.
Planners hope to select a winning project in time to include it in the 2015 Regional Transmission Expansion Plan.
Last month, they announced the selection of 11 other market efficiency projects with a combined cost of $59.2 million to address congestion in other areas of the footprint. (See “11 Market Efficiency Projects Selected; 12 still in running for AP South/AEP-DOM,” in PJM TEAC Briefs.) Those projects will be recommended to the PJM Board of Managers in October.
McGlynn noted that the RTO has done relatively few market efficiency projects in the past. “We’re very pleased to be having on the order of a dozen [market efficiency] projects to be taking to the board,” he said.
Planners also will reevaluate nine proposed projects to address constraints on the Loretto-Wilton Center 345-kV line, which caused the COMED locational deliverability area to bind in the 2018/19 Base Residual Auction in August. COMED cleared at $215/MW-day, $50 above the RTO price. (See PJM Capacity Prices Up 37% to $165/MW-day.)
The projects, with costs ranging from $11.5 million to $290 million, fell short of the 1.25 benefit-cost ratio in the original analysis. But one or more could clear the threshold if the analysis shows they can increase COMED’s capacity emergency transfer limit, McGlynn said.
Reliability Projects
The 2015 RTEP also will include reliability projects selected from among 91 proposals — 26 transmission owner upgrades and 64 greenfield projects — made in response to Window 1, which closed July 20. The window covered N-1 and N-1-1 thermal and voltage problems as well as generation deliverability and common mode outage and load deliverability issues.
The proposals range in cost from $13,000 to $167.1 million.
The RTEP recommendations also will include dozens of generation-related network upgrades (see pp. 34-68 of the PJM presentation).
Meanwhile, planners have begun reviewing proposals received in response to Window 2, which closed Sept. 4. The window sought solutions for transmission owner criteria and light load reliability criteria violations.
High Voltage Problem in AEP
Planners are considering more than $51 million in transmission upgrades to address a large increase in the number of high-voltage warnings in the AEP transmission zone and northeastern Mid-Atlantic regions. AEP also has seen a large increase in reactor switching for both low- and high-voltage conditions.
The problems, which generally occur during light load periods, are resulting from changes in dispatch due to new and deactivated generation, reactive support deficiencies and increased line charging from new transmission facilities.
Planners are considering spending $51 million to install a 450-MVAR static VAR compensator at the Jacksons Ferry 765-kV substation and a 300-MVAR shunt line reactor on the Broadford end of the Broadford–Jacksons Ferry 765-kV line in southern AEP.
They’re also planning six new shunt reactor installations in New Jersey, the cost of which is still being finalized.
Pratts Area Update
Planners said they will recommend selection of a Dominion project that requires no new right of way to address reliability problems near Pratts, Va.
PJM staff selected Dominion to build a 230-kV line from the Remington substation to the Gordonsville substation.
Dominion will build a new 230-kV line from the Remington substation to the Gordonsville substation and install a third 230/115-kV transformer at Gordonsville at an estimated cost of $103.7 million.
PJM announced last month it was reconsidering its selection of the Gordonsville-Pratts-Remington transmission upgrade after learning that it will require about 18 miles of new rights of way, far more than initially believed. The proposal from Dominion Resources and FirstEnergy was estimated at $129 million to $164 million.
The Virginia State Corporation Commission, which would have to approve the project, says that existing rights of way should be given priority as the locations for transmission additions.
In response to a question, McGlynn said planners had not independently verified Dominion’s assertion that the new line could be built in the existing 115-kV corridor. “We relied on the work of the entities that proposed the project,” he said.
A representative from Madison County, Va., which had urged PJM to reject the original plan, praised the new solution, saying it was “symmetrical with the identified need and an appropriate fix.” The county had complained that the original project was unnecessarily large for the rural county.
The cold weather temperatures produced by the polar vortex of January 2014 continue to haunt FERC.
The commission has denied another generator’s request for $1.3 million in make-whole payments for natural gas it purchased that was never used during the event, citing rules against retroactive ratemaking (ER15-952).
New Jersey Energy Associates, which owns the 290-MW South River combined-cycle plant, said PJM asked that a planned outage for the plant be canceled so it could be available for dispatch on Jan. 27, 2014. The plant purchased $2.7 million worth of gas, having been assured by PJM that it would be compensated for its fuel costs, according to NJEA. The RTO, however, repeatedly canceled the plant’s scheduled start time, forcing it to sell the gas at a $1.3 million loss.
The claims are similar to those of Duke Energy and Old Dominion Electric Cooperative. During the same week as NJEA’s claim, Duke purchased gas for $12.5 million when PJM said that its Lee plant in Illinois would be needed. The plant was never called on, however, and Duke was forced to sell the gas at a loss of $9.8 million. ODEC complained that PJM canceled multiple dispatches that left gas it had purchased unused and that it was due $15 million. (See Duke, ODEC Denied ‘Stranded’ Gas Compensation.)
FERC, however, remained steadfast on its assertion that these kinds of complaints constitute retroactive ratemaking.
“Ratepayers had not received any prior notice of NJEA’s requested relief, which was sought roughly 12 months after the events in question,” the commission said. “We therefore conclude, as we did in the similar Duke and ODEC cases, that the relief sought by NJEA is prohibited by the filed rate doctrine and rule against retroactive ratemaking.”
FERC, however, did find that NJEA was entitled to recover its start-up costs under PJM’s Tariff. The Tariff allows market participants to recover costs related to the start-up of resources offered in the day-ahead energy market if PJM cancels its selection of those resources. While NJEA did not specify how much they would be allowed to recover under this provision in its complaint, it said “this would only be a fraction of its actual unrecovered costs.”
As he did in the Duke and ODEC cases, Commissioner Philip Moeller dissented. He once again noted that PJM is the only grid operator that does not allow its participants to vary their day-ahead energy market offers by hour or update their offers in real time.
As a result of the Duke and ODEC complaints, FERC found that PJM’s Tariff was potentially unjust and unreasonable in this regard and ordered the RTO to make Tariff changes by Nov. 1. While PJM agreed that changes were needed, and it began the stakeholder process to do so, the RTO told the commission in July that it would need until Nov. 1, 2016, to resolve the numerous questions raised by the changes (EL15-73).
“In light of this delay in reforming PJM’s markets,” Moeller argued, “the majority’s repeated failure to guarantee cost recovery for generators acting in good faith to ensure system reliability may regrettably impact reliability during the approaching winter of 2015-2016.”
