PJM’s scheduling rules aren’t flexible enough to meet the needs of wind and other variable energy resources, the Federal Energy Regulatory Commission ruled last week.
The commission said PJM’s rules failed to meet the requirements of Order 764, which requires transmission providers to offer scheduling at 15-minute intervals. FERC ordered PJM to submit a new compliance filing within 30 days.
Prior to Order 764, the pro forma Open Access Transmission Tariff — developed for generation that could be scheduled with relative precision — included no option for adjusting transmission schedules within the hour.
As a result, variable energy resources could not avoid generator imbalance charges when they knew their generation was likely to change within the hour. Generator imbalance charges pay for energy the transmission provider must purchase when a generator’s output falls short of the amount scheduled.
The revised pro forma OATT requires that transmission providers allow scheduling changes be made within 20 minutes “or a reasonable time that is generally accepted in the region … before the start of the next scheduling interval.” The commission said it wanted to allow generators to adjust their schedules in 15-minute intervals.
PJM proposed amending the firm and non-firm point-to-point transmission service provisions of its Tariff to allow 15-minute schedules. But the commission said it was not compliant with Order 764 because the proposed Tariff required that the changes be made 20 minutes “before the next clock hour,” rather than before each 15-minute interval.
(As a practical matter, PJM said it does not assess imbalance penalties on any generators, because virtually no market participants use point-to-point transmission to serve load.)
Interchange Transactions
FERC also took issue with PJM’s practice of requiring that interchange transactions have a minimum duration of 45 minutes, which the commission said “is inconsistent with Order No. 764 because it does not allow a generator to schedule for less than three consecutive 15-minute intervals.”
PJM said it implemented the 45-minute rule on interchange transactions in 2008 to prevent “market abuses.”
In 2007, MISO and its Independent Market Monitor determined that nearly 60% of intra-hour schedules between MISO and PJM occurred in the final 15 minutes of the hour. PJM said the trading was the result of “market participants’ ability to see price differences between the two RTO markets for the first third of the hour and thereby predict with relative certainty the direction of the price separation between the two RTOs when the hourly integrated prices were calculated.”
PJM said this resulted in interchange spikes of up to 1,000 MW — increasing uplift charges because of the need to call on combustion turbines to balance the generation swings.
“A return to a 15-minute duration rule would cause an increase in imbalance charges [and balancing operating reserve] costs because it is entirely reasonable to expect that market participants would return to the [prior] practices,” PJM said.
Last year, the commission rejected MISO’s proposal to retain an existing requirement that schedules starting at the 30- and 45-minute marks of the hour be made by the beginning of the hour, which MISO said was intended to prevent the problems identified in 2007.
The commission last week granted MISO an extension until June 30, 2015 to fully implement Order 764.
Data Requirements
Order 764 also requires variable resources to provide meteorological and forced outage data to help transmission providers more accurately forecast generation. The commission accepted PJM’s addition of these requirements to its Tariff.
Calpine Corp. is selling six power plants in the Southeast and Midwest to LS Power for $1.57 billion in cash as part of a plan to focus on its electricity sales businesses in the Mid-Atlantic, Texas and California. The plants — representing a combined 3,498 MW — are in Alabama, Oklahoma, Louisiana, Florida and South Carolina.
Calpine spokesman Brett Kerr said the company planned to sell the six power plants for some time. It wanted to sell additional plants in Alabama, Arkansas and Florida but wasn’t able to get the price it needed for those assets. The LS Power deal is expected to close in the second quarter, and Calpine said it plans to use proceeds to pay down debt, buy back shares and possibly buy new generation.
The company operates 77 natural gas-fired power plants across the U.S., including 24 in California, 20 in Mid-Atlantic states and 14 in Texas. Calpine also has geothermal power plants in California.
PSEG’s Izzo Frustrated Over Opposition to “Energy Strong”
Ralph Izzo (Source: PSEG)
A frustrated Public Service Enterprise Group chief executive Ralph Izzo last week renewed his call for the state to approve a multibillion-dollar infrastructure-hardening project the company proposed shortly after Hurricane Sandy. In comments following PSEG’s annual shareholder meeting in Newark, Izzo questioned how the project’s opponents could maintain what he believes are two competing objections: that it costs too much and that it won’t help enough customers.
“The only way to reconcile those two is by saying, OK, we’re not proposing to spend the money in an optimal way,” Izzo said in an interview. “In which case, I say, we’re an open book. Tell us a better way to do it. And the reality is, there isn’t a better way to do it.”
Izzo said part of the planned 10-year, $3.9 billion “Energy Strong” project calls for strengthening facilities that were damaged by Sandy and Tropical Storm Irene. Newark-based Public Service Electric & Gas — PSEG’s largest subsidiary — filed Energy Strong with the state Board of Public Utilities in February 2013, four months after Sandy. While the utility maintains the project would improve reliability and help prevent the kind of massive power outages Irene and Sandy caused, opponents have pushed back against its price tag. The state Division of Rate Counsel, AARP New Jersey and a coalition of large energy users have also questioned the project’s stated effectiveness and the utility’s insistence on receiving approval for the money before starting construction.
As Stock Slides, Exelon’s Crane Gets 70% Raise in 2013
Christopher Crane (Source: Exelon)
Even as the company’s stock slid nearly 8% last year, Exelon Corp. CEO Christopher Crane was rewarded with a 70% raise, making more than $17 million in 2013. Crane’s total compensation in cash, stock and benefits topped out at $17.2 million, up from $10.2 million the year before. Crane’s compensation moved to a new performance-pay system that ties rewards over a three-year period rather than year-by-year. The company also eliminated stock options and moved its stock-based compensation to restricted shares and performance shares.
Exelon said it raised Crane’s pay to make it comparable to the median for peer CEOs. Before 2013, his pay was targeted at 20% less than the median. Exelon has suffered from falling wholesale power prices as its nuclear plants have grown less profitable. Increases at its regulated utilities — particularly ComEd, which is collecting annual delivery rate hikes per a state law authorizing $2.6 billion in local grid upgrades — have partially offset the declines at the power plants. But the 8% stock slide last year followed a 31% drop in 2012.
Duke Shareholders Urged To Oust Board Members Over Ash
Two of Duke Energy’s major institutional investors are urging fellow shareholders to vote out four directors at the May 1 shareholders meeting over the company’s ongoing coal ash problems. The California Public Employees’ Retirement System (CalPERS) and the New York City Pension Funds wrote shareholders last week, asking that they not reelect four board members responsible for environmental safety and health compliance.
Ash Spill (Source: Duke Energy)
The letter cites the Feb. 2 ash spill into the Dan River, saying Duke had “forewarning of the public risk” from environmental groups that had intended to sue Duke over ash contamination. None of the committee members named — Alex Bernhardt, James Hyler, James Rhodes and Carlos Saladrigas — has coal industry or other relevant experience, CalPERS and New York City comptroller Scott Stringer wrote. “In light of the serious failures of oversight, scale of impact on the company’s risk profile and the poor response to shareowner enquiry thus far, we urge our fellow investors to hold the relevant board members accountable.”
Duke said last week it has spent $15 million so far cleaning up the spill but said the costs would not be “material” to the company. Duke CEO Lynn Good has said Duke will pay for cleaning up the 70-mile trail of ash in the Dan River, but that it will ask the North Carolina regulators to approve ratepayer funding of costs associated with closing 33 ash basins at Duke sites across the state.
Duke had no immediate comment on the stakeholders’ action. CalPERS owned $140 million in Duke stock in 2013. The New York City funds have $62 billion in U.S. stocks, although it’s unclear how much of that is Duke stock.
PPL Generation, Trading Sale Rumors Fuel Stock Rise
PPL Corp. stock is trading near the top of its 52-week range amid continued speculation that the company may spin off its generation and energy marketing business. PPL shares closed Friday at $33.14, close to its 52-week high of $33.55. The rise came after the International Strategy and Investment Group raised its target price for PPL, citing the strength of its regulated utilities and the potential benefit if it spun off its generation. The report also cited the potential upside for PPL if it merged its power plants with another company’s.
A trade publication earlier this year published a report saying PPL hired Morgan Stanley and Citibank to conduct an internal review of PPL Energy Supply, the business arm that includes PPL’s generation and energy trading and marketing businesses. That report pointed at Dynegy as a possible buyer. PPL declined comment on any sale or spinoff rumors.
Dominion Virginia Power will conduct an earthquake risk assessment for its North Anna nuclear generating station but doesn’t expect the study to point to any significant modifications. The plant’s two 980-MW reactors were knocked offline by a 5.8-magnitude earthquake that shook central Virginia in August 2011. Although the temblor caused no significant damage, the station remained out of service for three months while the company and the Nuclear Regulatory Commission conducted a thorough safety check.
“These plants have so much design margin on the seismic side, I have no concerns about this whatsoever,” said David A. Heacock, president and chief nuclear officer of the parent company’s Dominion Nuclear operating group, said last week. “We verified our plant can withstand a stronger earthquake” than it was designed for.
In 2012, the U.S. Department of Energy, the Electric Power Research Institute and the NRC updated the seismic model for the central and eastern U.S., reflecting a greater seismic hazard at some nuclear plants than previously thought. Forty-seven plants will have to conduct additional studies to determine whether their designs protect them from earthquake hazards. Once the assessments are complete, the NRC will decide if plants require upgrades.
A judge allowed a competitor of a Delaware fuel cell company to challenge a state-sanctioned surcharge added on the bills of Delmarva Power customers last Thursday. U.S. District Court Magistrate Christopher Burke decided that FuelCell Energy, of Connecticut, can go forward with its suit against Delaware Gov. Jack Markell and the state Public Service Commission, saying it violated the Constitutional prohibition against state interference with interstate commerce.
The subsidy was created and approved by the commission in 2011 in a successful attempt to get Bloom Energy to move its fuel cell operation from California’s Silicon Valley to Delaware. The subsidy is funded by a surcharge on Delmarva’s residential customers averaging $4 to $6 a month. Burke wrote in his ruling that the tariffs help Bloom, but not FuelCell, and put FuelCell at a competitive disadvantage. There was no public solicitation for bids from out-of-state fuel cell companies.
ComEd Asking For Rate Hike; Says Improvements Paying Off
Commonwealth Edison Co. is asking for a rate hike, marking the fourth time since 2011 that the company has gone to regulators for permission to boost rates for modernization programs. The company said this increase request would add about $3 to the average electric bill. ComEd says improvements already undertaken have prevented 500,000 power outages, saving consumers about $82 million.
“These improvements, if done right, should pay for themselves in the long run, but the key moving forward is to hold ComEd accountable,” said Jim Chilsen, a spokesman for consumer advocacy group Citizens Utility Board in Chicago.
South Side Petcoke Storage Spurs Residents’ Outrage
(Source: MidWest Energy News)
Southeast Chicago residents vowed to take their fight to the streets over the increasing piles of petroleum coke being stored in their neighborhood. Saying they’ve been let down by elected officials who last year promised to crack down on companies storing the fuel, residents are planning an April 26 march and a boycott of BP, the source of the “petcoke” being stored along the Calumet River.
An expected City Council vote on an ordinance that would have limited petcoke storage morphed into a tamer proposed ordinance that allows more petcoke storage. Opponents are concerned the new ordinance would be the first step in the eventual approval of a contentious proposal for a synthetic gas plant in the area.
The gas plant plan was tabled last year after Gov. Pat Quinn vetoed legislation that would have committed Chicagoans to pay a fixed rate for synthetic gas from the plant for 30 years, even if market natural gas prices were much lower.
Ameren Brags on Upgrades; Critics Remain Unconvinced
Ameren Illinois’ pride in its transmission and distribution upgrades and resultant reliability improvements are being met with a jaded eye by some customers. The company said the $625 million spent on upgrades have shown a 20% improvement in reliability and savings worth $57 million a year since 2012 for residential and small business owners. Ameren Illinois was forced to make the investments, which included smart meter installations and energy-efficiency programs, under the Illinois Energy Infrastructure Modernization Act of 2011.
“This is a long-term process, but we have been able to deliver results to customers while keeping their rates reasonable,” said Ron Pate, senior vice president of operations for the utility.
Critics hope Ameren’s calculations are right but think the company may be jumping the gun. “We haven’t seen the evidence yet, and we think it’s too early to tell,” said David Kolata, executive director of the Citizens Utility Board public watchdog group. “It’s really going to be in the next six months that we’ll really start to get a read on it.”
East Kentucky Power Cooperative plans to shut down all four units at the 196-MW William C. Dale coal-fired power plant in Clark County over the next year, but the company said the two largest units will be held ready for restart if needed. East Kentucky decided that retrofitting the units so they meet 2015 pollution limits would be too expensive. The company said it has often been cheaper to operate other plants or purchase power from the market, particularly since East Kentucky’s 2013 integration into PJM.
“Dale Station was East Kentucky Power Cooperative’s first power plant,” Tony Campbell, the co-op’s president and CEO, said in a statement. “This plant has been a reliable workhorse, generating the electricity that powered many thousands of Kentucky homes and businesses over the past 60 years.”
East Kentucky also owns and operates the 341-MW Cooper baseload coal plant in Pulaski County and the 1,279-MW Spurlock baseload coal plant in Mason County. The co-op has installed pollution controls on both plants and intends to continue operating them.
The Public Service Commission is giving utility customers a gift after a brutal winter: a two-month extension to the period when certain utility companies can cut off service to non-paying customers. The new deadline is May 31, instead of March 31, and applies to Baltimore Gas & Electric Co., Potomac Electric Power Co. and Delmarva Power Co.
The utilities themselves had proposed the extension during a meeting with the commission. The commission is calling for all Maryland utilities to adopt the extension and wants utilities to move faster in switching customers with smart meters to competing retail suppliers when asked.
Southern Maryland Electric Cooperative signed a 20-year power purchase agreement last week with the developers of a proposed 10-MW solar facility in Charles County. Under the PPA with Juwi Solar Inc., SMECO will purchase all energy, capacity and renewable energy credits from the Rockfish Solar farm. If approved by the Public Service Commission, the $40 million project is scheduled to be completed by the end of the year.
SMECO has a 5.5-MW solar farm in Hughesville and purchases energy from two wind projects in Pennsylvania.
Attorney General Roy Cooper is returning to the state Supreme Court to try to block Duke Energy’s recent rate increase. Cooper argues that the state Utilities Commission failed to weigh the rate hike’s economic impact on Duke’s electricity customers.
The Utilities Commission originally approved Duke’s 7.2% rate increase in 2012 and upheld its decision in 2013. The state Supreme Court agreed with Cooper the first time around, setting up the current challenge. Now Cooper says the Supreme Court needs to send a clearer message to get the point across.
“The commission’s position is deeply unfair to consumers,” according to the attorney general’s legal challenge, which was filed Thursday.
Duke said the commission did everything correctly. “We believe the commission’s order satisfies all of the requirements set out by the N.C. Supreme Court and that the commission properly weighed the evidence,” the company said in a statement.
Thomas W. Johnson was sworn in last week as the new chair of the Public Utilities Commission, bringing with him experience in finance and budget issues from 22 years in the Ohio House. Johnson takes the helm of the 330-person agency for a five-year term.
(Source: PUCO)
Gov. John R. Kasich swore in Johnson Wednesday, after expressing misgivings over the state’s move to retail choice.
“The ideological effort to deregulate, I’m not so sure it’s the smartest thing we’ve done in the state of Ohio,” Kasich said, speaking to the audience in the PUCO chamber before the swearing-in. “But we are where we are, and we can’t go backwards now. So it’s onward in a deregulated environment, and we’ve got to figure it out.”
Poll Shows Ohio Voters Back Renewables, Efficiency
Ohio residents overwhelmingly favor using renewable power to replace coal-fired generators and want utilities to help customers increase energy efficiency, according to a poll commissioned by a green energy advocacy group. The telephone survey of Ohio voters found that 72% favor renewable energy over traditional power plants and 86% favor mandated utility energy efficiency programs. Two-thirds of those polled said they would back legislative candidates who promote renewable power over those who continue to support coal and nuclear power plants.
The poll was commissioned by Ohio Advanced Energy Economy, which opposes a Republican-backed bill that would freeze energy-efficiency efforts at the current level pending a study.
AEP Consolidating TX Ops To New Building in New Albany
American Electric Power plans to build offices in New Albany for its division that manages the interstate flow of electricity, bringing together about 500 workers who are now based at several central Ohio locations.
AEP Transmission Executive Vice President Lisa Barton said the company expects “significant cultural, operational and efficiency benefits” from having all transmission operations employees in one spot. The new headquarters will be completed in about two years.
PPL Electric Utilities wants to update its price to compare for default electricity customers twice a year, rather than quarterly, according to a proposal filed with the Public Utility Commission. PPL said twice-yearly prices “will provide customers more certainty around shopping and provide retail suppliers with more time and flexibility in creating pricing programs to encourage customers to shop.”
The price to compare is the price customers pay for generation and transmission if they don’t choose a competitive electricity supplier. PPL’s plan would cover the period from June 1, 2015 to May 31, 2017. The PUC is expected to rule on the request in early 2015.
Appalachian Power will ask the State Corporation Commission to let it increase the monthly residential customer charge from $8.35 to $16, but offset that by decreasing the base rate for each kilowatt-hour used. The SCC has set a Sept. 16 hearing date in Richmond to review the electric provider’s rates.
The SCC will review Appalachian Power’s generation, transmission and distribution rates, with any changes approved to take effect early next year. Appalachian Power also is seeking to establish two residential energy-efficiency programs. Appalachian Power serves about 500,000 customers in Virginia.
After several months of evaluation, PJMis close to naming a developer to fix the Artificial Island transmission stability problem, with LS Power’s proposal for an overhead crossing of the Delaware River holding on as the lowest-cost choice.
PJM’s Paul McGlynn told the Transmission Expansion Advisory Committee last week that the RTO will schedule a special meeting shortly — preferably before the next TEAC meeting May 8 — to discuss its evaluations of the proposals in detail. PJM expects to recommend a winner to the Board of Managers in July.
The presentation to the TEAC listed 10 apparent finalists among the 26 proposals submitted in July, including five that would add a 17-mile 500-kV line that parallels an existing 500-kV line from Red Lion to Hope Creek.
Five other proposals would cross the Delaware River to the Delmarva Peninsula south of Artificial Island with a 230-kV line and run to a new or expanded substation. Three of the proposals would run a submerged line in the river bed and two others would run the line above the water.
McGlynn said PJM planners and the RTO’s engineering consultant concluded that they needed to add options that increased the proposals’ price tags by as much as $192 million. The additional costs included an additional cable for the submarine crossings and an auto-transformer to proposals that included only one bank.
LS Power’s overhead proposal, the lowest cost proposal by its own estimate, remained the cheapest in PJM’s recalculation.
Dominion’s overhead proposal tumbled from second to fifth as PJM added $125 million in costs, nearly doubling its price tag. The Pepco Holdings/Exelon proposal received the biggest boost in the relative rankings, rising from sixth to second even as PJM added $59 million in costs.
PSEG’s cost estimate was the only one reduced by PJM’s calculations, though its ranking rose only from 10th to seventh.
The review estimated all of the projects would take about two years to build. For the Southern Delaware crossing proposals, it identified obtaining permits for the river crossing and crossing Delaware Route 9, a “Scenic and Historic Highway,” among the chief scheduling risks.
The Red Lion proposals face challenges including coordinating with the Salem and Hope Creek nuclear plants and the need to take out of service line 5015, which has had no more than an eight-day outage in the last 15 years.
Stakeholders have raised several technical questions about the proposals, including directional carrier blocking (DCB) schemes and the performance of static VAR compensators (SVCs).
Esam Khadr of PSE&G questioned the security of using DCB schemes and reliability of using SVCs.
“There are 3,800 MW of generation at Artificial Island. If the SVCs fail to respond to a severe disturbance, it could lead to unit instability [at Artificial Island] and a loss of the electrical system,” he said.
Steve Herling, vice president of planning, said planners will conduct market efficiency studies on the proposals before selecting a winner, but that they are unlikely to have a major impact because there is little congestion in the area.
WASHINGTON — PJM and the Federal Energy Regulatory Commission were summoned to the Capitol last week to defend their actions to ensure reliability — FERC in response to sabotage concerns, and PJM in the wake of an extraordinary winter that featured more near calamities than a James Bond movie.
The early expectation was that last month’s leak of a FERC study revealing the grid’s vulnerabilities would dominate the hearing before the Senate Energy and Natural Resources Committee and new Chair Mary Landrieu (D-La.). The day before the hearing, the Department of Energy’s Inspector General released a report that criticized FERC’s security procedures. (See related story, IG Faults FERC on Leaked Sabotage Report)
But the hearing instead focused largely on how PJM — after resorting to voltage reductions and load shedding in January — will keep the lights on over the next two years, as economics and EPA regulations idle 40,000 MW of coal-fired generation.
Role for Coal
Senator Joe Manchin
It was a stage, and a topic, that Sen. Joe Manchin had been waiting for. Manchin, the West Virginia Democrat who put the final bullet in the FERC nomination of Ron Binz last year, was the most animated person in the hearing room.
Manchin cited a report by AEP that 89% of the coal capacity that it will retire in the next 14 months was dispatched in January.
“I’m not here trying to push a product that you don’t want,” Manchin insisted, referring to coal. “But when we hear from people like you, the professionals, who say we’ve gotta have it. And I’ve got an [Obama] administration that’s fighting me every way they can, to get rid of it,” he said, shaking his head over the contradiction.
Then Manchin concluded with a triplet worthy of Yogi Berra: “You gotta have it, but you don’t want it, but you know you need it.”
Natural Gas Dependency
Thad Hill, Calpine
Several witnesses and senators expressed concern over growing too dependent on natural gas. But Calpine CEO Thad Hill, whose company’s generating fleet is 95% natural gas-fired, had no nostalgia for coal.
Of the 30,000 MW of PJM generation that suffered outages due to mechanical problems in January, Hill said, almost 15,000 MW were coal-fired versus only 1,500 MW of modern combined cycle. (Another 7,500 were older gas units, Hill said.) “The point being: This isn’t about overreliance on any one fuel. It was about operational readiness this winter.”
While PJM will lose 15,000 MW of coal over the next three years, it will get 19,000 MW of new resources, Hill said, including a 309-MW combined-cycle plant Calpine is building in Dover, Del.
He noted that the current retirements, sparked by EPA’s Mercury and Air Toxics (MATS) rule, is thinning the coal fleet of its most aged and inefficient units. The median AEP plant being retired is about 50 years old and less than 200 MW.
Nick Akins, AEP
The coal fleet is certain to be reduced further after the EPA announces its greenhouse gas regulations for existing generation in June. (See related story, Now Comes the Hard Part) In addition, some nuclear generation is at risk due to low energy and capacity prices and pending EPA cooling-water regulations.
AEP CEO Nick Akins complained that PJM’s capacity market was “not functioning as intended.
“Yes, PJM has more than 8,000 MW of planned (mostly gas) generation identified in the last two auctions, but many of those generators are being proposed with some form of state regulatory funding support,” he said in his written testimony. “What this means is that many new builds are the result of state directives rather than a response to market signals.”
Kormos: PJM is Prepared
PJM Executive Vice President for Operations Mike Kormos noted that the RTO’s fuel diversity will actually increase over the next few years as coal is replaced by gas and other resources. Coal will remain one-third of PJM’s capacity, he noted.
PJM generation capacity is expected to drop by almost 3,500 MW through 2017. (See chart.) Nevertheless, Kormos told the senators that PJM’s capacity auction has obtained more than its required energy and reserves “through the MATS [transition] period.”
He acknowledged challenges ahead. For one, Kormos said, there will be more price volatility as a result of the replacement of coal by natural gas and demand response, which he described as “one of highest priced resources.”
After enjoying several years of low-priced shale gas tranquility, natural gas generators were jolted in January when prices briefly spiked to more than $100/mmBtu. Kormos said PJM’s costs also were boosted in January by what he called the gas pipeline industry’s “onerous” contract provisions.
“It would not be realistic for me to stand up here and tell you that there will never be an interruption in service,” he said. “But … we will be able to serve the load in all but the most extreme circumstances.”
Moeller: Not Confident in Retirement Data
Commissioner Philip Moeller said he is troubled by contradictory capacity forecasts.
Commissioner Philip Moeller, FERC (L) and Mike Kormos, PJM (R)
“We have executives who say we can get through this period without any problem,” he said. “We have others who are very concerned. My focus has been to try and get the data: which plants retire when; where they are on the system.
“We’re not exactly confident in a lot of the numbers,” he continued. “And that has me very concerned going into the next two to three years.”
Moeller cited MISO, which recently predicted a 2-GW capacity shortfall in summer 2016 — down from estimates a few months ago of a 6-GW deficit. He noted that the revised projection assumes an annual 0.75% drop in energy consumption. “That’s a pretty big assumption,” he said ruefully.
Moeller’s prediction: “A lot of it’s going to depend on the weather. If we have mild weather for the next couple of years we might make it through. But if we have extreme weather in the summer or … in the winter, the system will be extremely stressed.”
The Federal Energy Regulatory Commission lacks proper controls for identifying and handling classified national security information, the Department of Energy’s Inspector General said last week.
Gregory H. Friedman issued his preliminary findings in a report issued on the eve of FERC’s appearance before the Senate Energy and Natural Resources Committee Thursday.
The IG review was initiated in March in response to news reports that included non-public information regarding FERC modeling on grid vulnerabilities and the investigation into the April 2013 attack on Pacific Gas and Electric Co.’s Metcalf substation.
The IG report said DOE’s subject matter experts concluded that at least one presentation created by commission staff should have been classified when it was created.
Article Cited
Although the report did not identify the presentation, Acting FERC Chair Cheryl LaFleur told the Energy Committee Thursday it was modeling created in early 2013 that was the subject of a March 13 Wall Street Journal article.
The article said the modeling indicated that disabling just nine critical substations could blackout the continental United States — a conclusion some experts have questioned.
“Based on preliminary information, we determined that the presentation was accessible to, and in specific instances, was viewed and handled by Commission employees who may not have had personnel security clearances and thus, were not fully aware of their obligation to protect the information,” Friedman said in a management alert. “Similarly, the document was reported to have been maintained on portable electronic equipment and transmitted via unsecured means.”
The document’s contents may “have been provided to both Federal and industry officials in unclassified settings,” the report added.
LaFleur had requested the IG review along with Senate Energy Chair Mary Landrieu, D.-La., and ranking member Lisa Murkowski, R-Alaska. LaFleur told the committee Thursday she had ordered FERC staff to make implementation of the IG’s corrective recommendations a top priority.
Scrubbing Computers
Cheryl LaFleur, acting chair, FERC
LaFleur said that the presentation was created in early 2013 and should have been classified at the secret level or higher, rather than as Critical Energy Infrastructure Information (CEII), a level of information that can be obtained by many FERC employees.
FERC responded to the IG findings by “gathering any paper copies we can find … wiping and scrubbing all databases and computers, and any portable devices across the commission,” LaFleur said.
She said the commission also is “reaching out to former employees including our former chairman [Jon Wellinghoff], and trying to get our arms around any information that may be out there.”
Wellinghoff, who was chairman from 2009 until December 2013, has been widely quoted in news accounts since leaving the commission during his campaign to raise awareness of the threat of sabotage. Each of the current commissioners has criticized Wellinghoff, both for going public with his concerns and for not doing more to address them when he headed the commission. (See FERC Criticism of Ex-Chair Mounts.)
Wellinghoff told Politico last month that he and another FERC official had briefed hundreds of people about the study and that the information in the Journal article was no secret. “There was no classified information,” he said. “There was no secret information and nothing was shared with anybody that was in any way part of some unpublished report.” He did not respond to requests for comment last week.
NERC: Attack was ‘Turning Point’
At least two saboteurs are believed to have taken part in the Metcalf attack, which caused more than $15 million in damage and idled the substation for nearly a month, but caused no power interruptions.
Gerry Cauley, president of the North American Electric Reliability Corp., who also testified before the committee, said the attack was a “turning point” that indicated security measures designed to keep intruders from getting onto substation property were insufficient.
“We’re doing the right things and were doing the right things on a prioritized basis,” he said. “… The Metcalf incident was serious but it’s also a good example of the resiliency of the grid — there were no customer outages.”
American Electric Power expects coal to represent 51% of its generation portfolio in 2020, down from 65% in 2012 but up from an earlier prediction of 46%. Coal’s gain will reduce growth in the company’s natural gas portfolio. Natural gas lost market share to coal last year in PJM due to rising gas prices.
Dominion is buying six California solar development projects with a combined output of 139 MW from Recurrent Energy. The acquisition will greatly raise Dominion’s solar portfolio from its current 41 MW in Georgia, Connecticut and Indiana. The new projects, which already have power purchase agreements and are under construction, are scheduled for commercial operation later this year or early in 2015.
Exelon Absorbs CENG Units, Bringing Fleet to 22,000 MW
Exelon has integrated the operations of Constellation Energy Nuclear Group’s five reactors into its own nuclear group, adding 4,200 MW of capacity to bring its nuclear fleet to more than 22,000 MW in 23 reactors at 14 sites. Exelon thus is the world’s third-largest nuclear operator, behind French state-owned Electricite de France (EDF), with 63,130 MW, and Rosenergoatom in Russia, which has 25,200 MW.
CENG still exists, with 50.1% owned by Exelon and 49.9% by EDF. But last summer the companies made a deal whereby Exelon lent $400 million to CENG to support a special dividend to EDF and granted EDF an option to sell its CENG stake to Exelon between January 2016 and June 2022 at fair market value.
The move was envisioned when Exelon bought CENG’s parent, Constellation Energy, in 2012. At that time the Nuclear Regulatory Commission approved the indirect transfer of the operating licenses, and now the NRC has approved a direct transfer.
Energy market rules have not kept up with “seismic shifts in how energy is produced and consumed,” Exelon Generation President and CEO Kenneth Cornew said. He cited the influx of natural gas, rapid expansion of subsidized renewables, smart grid, low demand growth and behind-the-meter technologies. Focusing on a theme Exelon has used heavily, Cornew told the Platts Global Power Markets Conference that markets need reform. The winter’s polar vortex, with its disruption of gas supply to power plants, highlighted a continuing need for baseload assets like nuclear power, he said, but “flawed market rules” and renewables subsidies result in failure to compensate nuclear for its reliability and zero-emission quality.
FirstEnergy CEO Anthony Alexander believes that “state and federal policymakers are manipulating the supply and demand, and distorting markets for electricity, to further advance the ‘war on coal.’” Speaking at a U.S. Chamber of Commerce event, Alexander lambasted state and federal energy policies that he said were “designed to achieve a social agenda.” He warned that efficiency, renewables, microgrids, rooftop solar and demand reduction are examples of what “sounds good” but are “untested policies” that will threaten reliability and raise power prices.
NRG Closes Deals to Grow Capacity, Retail Presence
NRG Energy closed on its $2.6 billion purchase of Edison Mission Energy generating assets and the $165 million purchase of Dominion Resources’ competitive retail electricity business.
Edison Mission’s nearly 8,000 MW brings NRG’s fleet to more than 53,000 MW, second-largest in the U.S. Dominion’s retail business will add more than 500,000 accounts to NRG’s retail footprint by the end of this year, doubling the company’s Northeast retail presence and expanding its leading retail position in Texas through the Cirro Energy brand.
Completion of the purchases followed on the heels of NRG’s purchase of Roof Diagnostics Solar, a solar sales and installation company.
PJM will resettle $89 million in bills due to logging errors that caused overcharges of load serving entities in the eastern portion of PJM and undercharges for those in the west. The improperly inputted data incorrectly placed RTO-wide charges entirely in the eastern zones, PJM’s Joe Ciabattoni told the Market Implementation Committee last week.
Ciabattoni said an unusual transaction code used during the polar vortex led to a “misunderstanding in the control room.” The “regional conservative operations” code has since been eliminated.
Suzanne Coyne, of PJM Settlements, said the issue was discovered in February and adjustments were made in the March bills, which were distributed last week.
More details will appear on Delmarva Power bills, after lawmaker complaints that there was too little information about state-mandated charges, including purchases of renewable power and the Bloom Energy surcharge.
In meetings at the Public Service Commission, a two-step process was agreed on: First, this summer, utility bills will add line items for the low-income fund charge, the Green Energy Fund charge and “renewable compliance charges,” which will be wind, solar and fuel cell charges lumped together. The next step comes in 2014, when wind, solar and fuel cell charges will be detailed. The PSC must approve the agreement.
The Bloom Energy charge is on bills because lawmakers allowed the natural gas-powered fuel cell energy to count for renewables requirements. A Bloom subsidiary put a project at two Delmarva substations, and customers are paying a surcharge each month for the energy.
The Public Service Commission approved a $15.1 million delivery rate increase for Delmarva Power, less than half the $38.9 million the company sought. It allowed a 9.7% return on equity instead of the 10.25% sought.
NRG’s Crane: Coal Plants ‘Essential’ for 3-10 Years
NRG Energy chief executive David Crane said that he has not developed a long-term plan for the Illinois coal plants the company just bought from Edison Mission Energy’s Midwest Generation. But he said they will be essential in the short term.
“The purpose of having old coal plants, to be frank, is keeping the lights on for the next three, five, 10 years,” he said. “All I can say is thank God” old coal plants were available in this winter’s frigid spells, he said, because “there just isn’t enough natural gas in the system.”
Asked about Exelon’s position opposing subsidies for wind and solar, NRG’s Crane called it “hypocritical,” when Exelon “purports to be this super-green company and also wants more subsidies for nuclear.”
ComEd is partnering with Nest Labs to offer up to $140 in rebates for customers who buy a Nest Learning Thermostat and participate in the utility’s demand response program. ComEd’s AC Cycling pilot program, in effect from June through September, can use Nest’s Rush Hour Rewards service to help reduce demand on the hottest days, the utility said.
Retailer IKEA US is buying a 98-MW wind farm in Hoopeston, Vermilion County, the company’s first wind farm investment in the U.S. and IKEA Group’s largest single renewable energy investment globally. Hoopeston Wind is being built by Apex Clean Energy and is expected to be online by the first half of 2015.
Big Sky Wind Farm (Source: ridiculousRICL.blogspot.com)
Big Sky Wind Farm west of Chicago now belongs to Pittsburgh-based EverPower Wind Holdings. Turbine-maker Suzlon Energy bought the 240-MW facility from Edison Mission Energy (EME) at the beginning of April and immediately sold it to EverPower, in a pair of transactions that resolved Suzlon’s long-running dispute with EME, which involved a $228 million loan Suzlon made to EME.
EME had withheld $208 million, charging that Suzlon supplied defective equipment. The sale price was not disclosed, but the deal provided cash-strapped Suzlon with liquidity, which is “very valuable” right now, Suzlon finance group head Kirti Vagadia said. He said in February that it expected to recover $90 million from the asset.
The Indiana Utility Regulatory Commission will look further into the fuel costs that Duke Energy Indiana has reported for its long-troubled Edwardsport integrated gasification plant, whose output fell to under 1% of capacity in February. The 618-MW plant ran at 4% in January. The state Office of the Utility Consumer Counselor claims the $3.5 billion plant consumed more energy than it produced during some periods in September, October and November, and pressed the IURC for more time to scrutinize Duke’s request for fuel cost recovery. Duke argues the plant is within its 15-month startup plan, but the commission agreed to take a deeper look.
The Public Service Commission approved Old Dominion Electric Cooperative’s 1,000-MW, gas-fired Wildcat Point generating project. ODEC plans to build the combined-cycle project next to its existing Rock Springs gas facility in Cecil County and is targeting a June 2017 in-service date. Transcontinental Gas Pipeline is applying for approval to build a pipeline to serve the project.
Retail customers will now be able to change energy suppliers more quickly, get budget billing plans as well as payment extensions and obtain other help with electricity bills – some things that Baltimore Gas and Electric has already been offering its customers since January’s price spikes. The Public Service Commission approved these provisions after hearing hundreds of complaints about prices, and about receiving misleading information from suppliers about their variable rates and how to cancel contracts.
People’s Counsel Paula Carmody said her office has been puzzled by variable rate contracts up to 48 cents/kWh, compared with BGE’s standard offer of 9.5 cents. Disclosure rules have to be changed, she said, and there should be consideration of capping variable-rate contracts.
The future of Pioneer Green’s wind project in Somerset County appears to be in the hands of Gov. Martin O’Malley, who will either sign or veto a lawmaker-approved bill to delay wind farm development within a 56-mile range of Naval Air Station Patuxent River while a study is done to see how turbines can operate without interfering with radar.
The bill targets Pioneer Green’s 25-turbine project, Great Bay Wind Energy Center. While the developer has an agreement with the military concerning operational measures to allay radar concerns, some interests are far from sanguine about it. O’Malley favors wind development and reportedly has been eager to move the Somerset project along.
But U.S. Rep. Steny Hoyer (D-Md.) and others have called for a delay. The Patuxent air base is a major economic presence in Maryland.
The Maryland Energy Administration is soliciting applications until May 15 for $1.1 million in grants for community-scale wind power projects, from 100 kW to 1,000 kW. Projects for Community Windswept grants must provide a benefit such as community ownership or serving load at a local community, academic or municipal facility.
Fishermen’s Energy is appealing the Board of Public Utilities’ denial last month of its plan to build a 25-turbine wind farm offshore Atlantic City. The appeal is “to clarify a number of apparent misunderstandings and misinterpretations,” including a large overestimation of the price of the project’s power, the company said. According to Fishermen’s, the BPU reviewed a price of $263/MWh while the real price is $199.
The state should look at a range of options for reviving its leadership in deployment of solar energy, according to a draft report, from establishing a “green bank” to help finance new installations to promoting more competitive procurement of long-term contracts. The report was prepared for the Rutgers University Center for Energy, Economic and Environmental Policy, which is working with the Board of Public Utilities on solar development volatility. The state used to rank second in the number of installations but has slipped to fifth. Policymakers are concerned about the boom-and-bust cycle.
After devastating outages in the last few years, the Board of Public Utilities is toughening its requirements for utilities’ vegetation management practices. “We’re going to get in your face a little bit more than in the past,” the BPU’s Jerome May told utility executives. While the board conceded that utilities generally do a good job with trees, it said more needs to be done, especially in communicating with local officials about tree-trimming policies.
Duke Energy has received bids for almost three times the 300 MW of new solar capacity it sought in a February request for proposals. The 300 MW would almost double the utility’s solar capacity in the state. The RFP targeted facilities larger than 5 MW and was limited to projects already in Duke’s transmission and distribution queue that could be completed by the end of 2015. Duke said it would select projects by October.
Communities along the Dan River on the North Carolina-Virginia border are pressing Duke Energy to use vacuum dredgers to clear the waterway of coal ash from a Feb. 2 spill. At least one county resolution also called on Duke to remove ash from all 13 ponds at several facilities in the river’s basin. According to the Roanoke River Basin Association, the pollution in the river from the Dan spill is hurting tourism in the economically depressed region.
In other action, a judge denied Duke’s motion to shield records related to ash-pond groundwater pollution while the separate federal criminal investigation is going on. The judge agreed with a Southern Environmental Law Center attorney to keep the documents public but said Duke could try later to seal some of the records as trade secrets if they could justify it.
Duke Energy East End Gas Works (Source: Duke Energy)
Duke Energy and Piedmont Natural Gas are asking for proposals to build and operate a second large natural gas interstate pipeline into North Carolina. Duke has opened five gas-fired plants in the state since 2011 and plans a continuing shift to gas. Piedmont’s customer growth last year was its highest since 2008 and continues to climb.
The state is now served by a Transco line that runs northeast diagonally through western North Carolina. Duke and Piedmont want the new pipe to take a different route. They are open to various kinds of ownership arrangements. The companies expect to select a proposal by the end of this year and to have the project completed by late 2018.
Duke Energy said it temporarily stopped using a vegetation management product that has raised a storm of public concern about safety. The product, Cambistat, stunts tree growth and keeps limbs away from power lines. Duke crews have injected the chemical into the soil near hundreds of trees; it plans on using the product in Charlotte, Greensboro and Durham. The company and the product maker maintain Cambistat is safe and actually makes trees healthier. A Duke spokeswoman said the company failed to inform customers adequately.
A new Columbus Energy Review Committee will explore whether the city should enter the energy aggregation market. The committee will meet with communities that already participate in aggregation to lower their costs. Most electricity aggregation occurs in northern Ohio. Mayor Michael Coleman and the City Council gave no specific motivation for investigating the option. Coleman spokesman Dan Williamson said only that “What the mayor and council president say is `it’s something worth studying.’”
Members of American Municipal Power are to meet this week to discuss how to proceed – appeal, settlement attempt or other route – after a federal judge rejected their effort to force Bechtel to pay up to $97 million for costs of a Meigs-area coal plant that AMP canceled in 2009. The judge ruled that AMP did not show Bechtel acted recklessly and thus the municipal power supply organization could not seek more than the $500,000 damages specified in the contract. Among AMP members, Coldwater Board of Public Utilities, for example, owes just more than $3 million in stranded costs, and Hillsdale Board of Public Utilities owes just more than $1 million.
FirstEnergy Gets Scrutiny For Cold-Spell Extra Fee
The Public Utilities Commission is investigating FirstEnergy Solutions for the one-time fee it is charging fixed-rate competitive-supply customers for its extra costs associated with the January cold spell. The company plans to attach a fee of $5 to $15 to residential bills and up to 3% to business bills. The commission is looking into how the contracts are marketed to customers.
FirstEnergy Solutions is taking heat in Pennsylvania, too, where Public Utility Commission Chairman Robert Powelson is one of its customers. Fixed rates are fixed rates, he said, and “I think there’s a stench” associated with the company’s fee.
The company’s extra costs came from the extraordinarily high wholesale prices in PJM when extreme cold struck the region, cutting some power supply.
Gas-Plant Cleanup Measure Pulled from House Agenda
Lawmakers stopped action on a measure that would have allowed utilities to charge customers for cleanup costs at 19th century manufactured-gas plants, where gas was made from coal and other fuels. The measure, part of a budget package, was pulled after it became more complicated with the addition of electric utilities to those that would be permitted to seek cost recovery for the cleanup work. Known costs so far are about $80 million for projects by natural gas utilities Duke Energy and Columbia Gas of Ohio. Electric companies American Electric Power and FirstEnergy each have 11 sites, for which cleanup costs are not yet estimated.
Opponents say customers should not have to pay, and they warn the proposal could signal a broad liability shift that could be extended to other arenas, like coal ash ponds and coal-fired plants. Doug Colafella of FirstEnergy called those predictions “just hyperbole.”
American Electric Power Ohio customers will pay $2.34 extra per household bill and $9.67 per business bill to cover the utility’s $57 million repair costs after the 2012 derecho. The Ohio Consumers’ Counsel had opposed the payment agreement that the Public Utilities Commission approved. AEP spokesman Phil Moye said the company probably would file for a similar deal in West Virginia to recover the $71 million in derecho costs incurred there.
Bill to Freeze Green Levels Gets Big Pro, Con Lobbying
As the legislature contemplates a bill that would freeze the state’s renewable power and energy efficiency mandates at their current level, big business interests are pressing lawmakers both for and against it. FirstEnergy is a leader in support of the freeze, along with Marathon Petroleum and Timken Co. while opponents include Honda, Whirlpool and Owens Corning.
The measure, Senate Bill 310, would halt at 2014 levels the renewables and efficiency levels set in a 2008 law, which raised the requirements annually to 25% by 2025. Some large users say the utility-bill fee for the program is costing much more than the benefits.
FE Making Changes to Help Prevent Lake County Outages
FirstEnergy will change insulators on power lines in Lake County, in The Illuminating Company territory, to cut the risk of another prolonged power outage after two outages in the first two weeks of March that left tens of thousands of customers without power. The work, which should be complete by the end of the year, will involve changing porcelain insulators to polymer insulators and adding switchers. Local officials told utility representatives that communication during the events was a problem. The representatives suggested conference calls and a special smartphone app to improve communications.
All of Ohio’s regulated utilities met Public Utilities Commission requirements for reliability last year, PUC documents show. American Electric Power had an average of 1.03 failures per customer with an average duration of 141 minutes — not counting major storms, which are excluded from the PUC standards. AEP had been aiming for less than 1.2 outages and 150 minutes in duration. Each company has its own requirements, set to take local conditions into account.
Former PUC Chairman Todd Snitchler has a new job in the Columbus office of McDonald Hopkins, a business advisory and advocacy law firm. He will provide expertise on energy policy and strategy, government affairs and regulatory matters. Snitchler cannot argue cases before the PUCO for two years, but will be able to practice before other state commissions.
In addition to its Columbus office, the firm has locations in Chicago, Cleveland, Detroit, Miami, and West Palm Beach. Its Washington D.C.-based subsidiary, McDonald Hopkins Government Strategies LLC, is headed by former Ohio Congressman Steven LaTourette.
PENNSYLVANIA
PUC Mandates More Retailer Info, Shorter Switch Time
Public Utility Commission member Pam Witmer urged lawmakers to adopt a set of PUC regulations that would give electricity customers more information about their accounts and the ability to switch suppliers more quickly. Spurred by thousands of complaints of sky-high bills from retailers for the extraordinarily cold snaps this winter, the PUC instituted new rules to require clearer contract language and more disclosure about variable rates. The new rules also cut the time it takes to switch from an average of between 11 and 40 days to three days.
The Energy Association of Pennsylvania, representing utilities, said it would be challenging to adopt the faster switch period in the six months allowed, and said utilities lack the technology to close out bills fast enough to meet the new switching timeline. EAP CEO Terry Fitzpatrick also said accelerated switching would do customers little good in a price crisis, as it would be too late by the time they received their bills.
Meanwhile, the PUC released data that showed two competitive suppliers – IDT Energy and Pennsylvania Gas & Electric – accounted for more than half of the complaints the commission received. Ten suppliers accounted for 83% of the complaints. Chairman Robert Powelson said the commission could ultimately revoke the licenses of abusive suppliers.
FirstEnergy Gets 14 Years To Close Little Blue Run
The Department of Environmental Protection gave FirstEnergy 14 years to close the large Little Blue Run coal ash impoundment, which is associated with the Bruce Mansfield plant in Shippingport. The 14 years is more time than environmentalists wanted but less than the company sought. In a closure permit, the DEP requires FirstEnergy to monitor groundwater and surface water from more than 300 locations instead of the 74 the company had proposed, and it requires the company to control noise, odors and particulate emissions, among other measures. FirstEnergy agreed to stop pumping coal-waste slurry into the 978-acre pond by the end of 2016.
The DEP said FirstEnergy has posted a financial assurance bond of more than $169 million, the largest ever required by the state for a waste management facility.
PPL’s Susquehanna 1,300-MW nuclear Unit 2 can go back to normal Nuclear Regulatory Commission oversight if it clears one more hurdle: a thorough inspection to make sure root causes of its problems have been addressed. NRC representatives said at a public meeting near the plant that PPL is meeting the objectives set to fix troubles identified after four unplanned shutdowns in 2012 and 2013 that caused the agency to put the plant in special oversight status. Only five other U.S. reactors are in the “degraded cornerstone” status.
At the meeting, PPL detailed measures it has taken to improve operations and noted that it plans to spend more than $20 million in capital improvements and $40 million for maintenance at the plant.
FirstEnergy Starts Rollout Of 2 Million Smart Meters
FirstEnergy is poised to roll out two million smart meters to customers in its four Pennsylvania-based utilities. The several-year deployment, managed by Accenture, will be one of the largest advanced-meter deployments on the continent.
Southside Electric Cooperative has begun steps to replace a Dominion Power distribution line with a co-op-owned transmission line, in a plan for relieving an outage problem connected with the line. The current line, which serves the co-op’s substation in Dinwiddie, was ranked second-worst of 246 Old Dominion Electric Cooperative’s wholesale-power delivery points in Virginia, Maryland and Delaware. Standards for a transmission line — wider rights of way, for example — will provide more reliability than the distribution line does, the co-op said, although some local concerns remain about impact on historical sites.
PJM took its first step toward requiring cold-weather testing of generators, briefing the Operating Committee last week on a proposed problem statement it hopes will result in improved preparedness next winter.
The RTO says it wants to add operational testing and to reinstate winter-capability testing similar to what was formerly required.
As envisioned by PJM, generators would be required to conduct operational tests in December in which they start their units, synchronize them to the grid and operate at economic minimum or above for at least the minimum run time of the unit. The requirement would apply to generators that operate infrequently and those with dual fuel capability.
The winter capability test, which would measure plant output capacity, could be similar to tests that were eliminated in 2010 due to economic concerns and the addition of regional reliability standards. Since 2010, PJM has accepted summer test data corrected for winter conditions.
PJM’s action was prompted by the 22% forced outage rates during the polar vortex in early January. While 24% of these outages were related to gas interruptions, the bulk of the remaining 75% — approximately 30,000 MW of lost generation — were units that failed to start due to mechanical issues.
Forced outage rates were lower during a late January cold snap, leading to the conclusion that testing units in December before extreme cold typically strikes would help identify potential issues prior to peak winter load conditions. (See Winter Testing May Be on the Horizon.)
“Part of the reason we wanted to bring this up as a problem statement is that we realize we don’t have all the answers,” said Executive Director of System Operations Mike Bryson. He added, “We don’t think we can afford to see [a repeat of] what we saw last winter.”
Some stakeholders had questions about implementing the tests and how broadly they should be applied.
“It’s hard to test these conditions when you’re not in these conditions,” said Brad Weghorst, of PPL. “I’m not sure how much more operational performance you’re going to get under extreme conditions when you’re testing in December.”
One stakeholder representing a utility said he’d like to see demand response resources be included in winter capability testing.
“To exclude a set of resources such as DR that provides a significant portion of PJM capacity is a poor choice,” he said. “[Resource providers] are all getting paid the same, so I’m not sure why they’d get a way out of this and we’d have to pay” for testing.
Bryson said language in the problem statement and forthcoming issue charge could be changed from “Cold Weather Generator Testing” to “Cold Weather Resource Testing” to include DR before stakeholder approval is sought.
