PJM officials said they are pleased with the response to their request for additional black start resources, as more than 50 generators responded with offers.
“There appears to be a large pool of viable units, both proposed and existing,” said Mike Kormos, PJM executive vice president for operations.
Officials said it will take months to select their fleet of black start resources from among current resources and the new bidders. Locational needs and costs will be the determining factors.
Black start units must be capable of starting without an outside electrical supply, maintaining frequency and voltage under varying load, and maintaining rated output for a specified time, typically 16 hours.
The solicitation was one of the recommendations of the System Restoration Strategy Task Force, which also increased the pool of potential resources.
PJM expects to lose some existing black start capacity by 2015 due to coal plant retirements.
The PJM Board of Managers last week approved $1.2 billion in transmission reliability projects.
CEO Terry Boston said the projects in the 2013 Regional Transmission Expansion Plan (RTEP) will enhance grid resiliency and respond to the shift of generation from coal to natural gas.
PJM has approved more than $24.2 billion in transmission additions and upgrades since the first RTEP in 2000.
The plan includes upgrades and improvements to transformers, substations and other facilities.
The approved projects can commence as soon as the transmission developers receive required state and local regulatory approvals, said PJM Chief Financial Officer Suzanne Daugherty.
The Environmental Protection Agency’s proposal to regulate emissions from existing coal-fired power plants could result in creation of a cap-and-trade system on a regional basis.
EPA Administrator Gina McCarthy said that controls on existing plants would be imposed through something similar to the “state implementation plans” that the agency has required to regulate pollutants like sulfur dioxide and nitrogen oxides. The rules are scheduled to be issued next June.
The Supreme Court is expected to decide this week whether it will review a lower court ruling that upheld the Environmental Protection Agency’s greenhouse gas regulations.
Petitioners, including the U.S. Chamber of Commerce and the American Chemistry Council are asking the court to reverse aspects of an appellate court’s June 2012 ruling that backed EPA’s first rules following the Supreme Court’s landmark Massachusetts v. EPA decision, which instructed the agency to regulate greenhouse gases as harmful pollutants under the Clean Air Act.
The Nuclear Regulatory Commission said it has enough “carryover” funding to maintain normal operations for at least a week in the event of a government shutdown.
If the shutdown exhausts the agency’s funding, it will retain about 300 of its 3,900 employees, half of them resident inspectors assigned to reactor and fuel facilities, the rest staff who would provide initial response to an emergency at licensed facilities. The NRC Commissioners and Inspector General are exempted from furloughs because they are presidential appointees.
The Nuclear Regulatory Commission has commissioned the National Academy of Sciences to conduct a pilot study of cancer risks for people living around six nuclear plants. The pilot will determine whether to extend the study to other nuclear facilities.
The plants chosen for the pilot are Dresden station in Illinois, Oyster Creek in New Jersey, Big Rock Point in Michigan, Millstone and Haddam Neck in Connecticut and San Onofre in California.
The Federal Energy Regulatory Commission will keep 48 of 1,460 employees (3.3%) at work during a government shutdown to “protect life and property.” Most of the employees work in hydroelectric and liquefied natural gas inspections (19), legal and enforcement matters (10) and commission infrastructure (10). Also to be retained are 19 contractors providing building security and information technology support. The five commissioners also are exempted from furlough as presidential appointees.
A Senate committee aide said the Obama administration is eyeing other candidates to replace Ron Binz as its nominee for chairman of the Federal Energy Regulatory Commission.
Binz’ nomination is in doubt after he failed to win support from any Republicans on the Senate Energy and Natural Resources Committee. Sen. Joe Manchin (D., W.V.) also has said he will vote against Binz.
The research arm of the National Rural Electric Cooperative Association says frequent cycling of fossil units to accommodate wind and solar power could increase forced outages in such units from about 5% a year to as high as 25%. The group said baseload coal plants will experience “thermal cycle fatigue” after 12 to 18 months of being shut down at night and restarted in the morning.
NRECA released its analysis in response to a National Renewable Energy Laboratory study that concluded frequent cycling of fossil units in the Western Interconnection could save about $7 billion a year in fuel costs.
The Public Service Commission scheduled public comment sessions for Oct. 3 and 16 in its investigation into Delmarva Power’s request to spend $397 million over five years for infrastructure and reliability projects. The PSC staff expressed concern over the request, noting that the company, which received a rate increase late last year, already exceeds its reliability requirement by 51%. (Docket No. 13-152)
Rock Island Line Map (Source: Clean Line Energy Partners)
Developers of the proposed Rock Island Clean Line heard little encouragement from hundreds of Illinoisans at a public meeting. The proposed 500-mile, 3,500-MW DC line would carry wind power to Illinois from Iowa, Nebraska and South Dakota.
The president of the Illinois Farm Bureau said the line’s proposed path doesn’t follow farm property or section lines, which would make it difficult apply pesticides and use irrigation.
Voters in the unincorporated areas of Jefferson County may get a second vote on electric aggregation if the County Board votes this month to approve the item for next March’s primary ballot. An April vote on the question failed by only 104 votes, and about 700 voters did not cast votes on the item. A consultant plans better public education on the issue.
If approved, 70 communities will band together to negotiate lower rates.
Planned Woodbridge Energy Center (Source: Competitive Power Ventures)
Competitive Power Ventures has closed financing for its $842 million Woodbridge Energy Center. GE EnergyFinancial Services is providing financing, advanced generation technology and services for the 700-MW combined cycle plant, which is owned by CPV, ArcLight Capital Partners and Toyota Tsusho.
CPV Woodbridge will sell its capacity through 15-year standard offer agreements with New Jersey utilities.
The Ohio Manufacturers Association favors the state’s energy efficiency standards but wants a cap on how much utilities can charge for efficiency riders. The group said is still studying provisions of a bill that has been introduced to make changes in the program.
Meanwhile, wind energy supporters argued against a provision in the bill that would eliminate requirements that utilities buy a certain amount of in-state renewable energy.
Lt. Gov. Jim Cawley thinks state Attorney General Kathleen Kane went too far in lodging criminal charges against XTO Energy for a Marcellus Shale wastewater spill. “No one should be punished more than once for the same mistake,” Cawley said at a natural gas industry conference in Philadelphia. XTO previously agreed to pay a fine for the 2010 incident and spend $20 million to upgrade its wastewater management practices.
The Public Utility Commission asked for comments on its plans to improve utilities’ response to storm outages. The PUC is proposing creation of a working group of electric distribution companies (EDCs), telephone, and water, wastewater, and natural gas distribution utilities to coordinate restoration of services where more than one party is affected in a geographic area. The agency also issued a policy statement on outage response.
The Pennsylvania Public Utility Commission will investigate Duquesne Light’s proposal to raise its electric distribution rates 17.6%. The increase would fund grid upgrades, smart grid measures and vegetation management, the company said. The Office of Consumer Advocate is challenging it.
The PUC began streaming video of its regularly scheduled public meetings. It said it also will stream video of en banc hearings and other special meetings.
The Public Utility Commission fined Great American Power $10,000 for misrepresenting its relationship with electric distribution companies and engaging in abusive telemarketing. The Commission also said the company’s ability to operate as an electric generation supplier could be revoked if it fails to meet PUC requirements for documenting customer enrollments and addressing future complaints.
Panda Power Funds acquired a majority stake in the 750-MW Stonewall combined-cycle project planned for Loudoun County. Partners include Bechtel Development and Green Energy Partners/Stonewall, the original developer.
The state approved an air permit in April, and construction is to begin once financing and all permits are in hand. Panda expects the plant to be in service in 2017.
Dominion Virginia Power is on track to finish its 1,329-MW combined-cycle Warren County Power Station by the fourth quarter of next year, having hit the 50% completion mark last month after 17 months of construction that included building a 2.5-mile gas line. Warren County Energy Partners, a partnership of Burns & McDonnell and Zachry Construction, is building the station.
Appalachian Power is moving forward with its plans to spend $337 million on a project to upgrade electrical transmission lines and related facilities. The company has filed four petitions with the Public Service Commission regarding the project, and one of them received PSC approval last week.
The company said the work is needed to replace some facilities that were built in the 1920s to 1940s and a “backbone” power line from Poca to Cabin Creek that was last reinforced four decades ago.
Thirty-eight Keyser residents filed suit against the Pinnacle Wind Farm, alleging that sound from the farm’s 23 turbines on Green Mountain has caused mental and physical problems and reduced property values. The company, owned by subsidiaries of Edison International, denies the allegations.
PJM Chief Financial Officer Suzanne Daugherty briefed the Members Committee webinar on the spending plan last week.
Daugherty said PJM plans to add five staffers to its current workforce of 665.
PJM’s composite expense rate continues to be below the 2006 stated rate settlement projections, Daugherty noted.
The operating budget is in addition to a proposed $30 million in capital spending, down $2 million from 2013. (See PJM Plans $30M Capital Spend for 2014)
The Board of Managers is expected to consider the spending plan at a meeting tomorrow.
Thursday’s FERC technical conference on capacity markets elicited sharply differing views on a variety of design concepts and technical issues. Some of the disagreements have been around since the beginning of capacity markets, others are reflecting the influence of new technologies.
Below is a summary of some of the key issues.
Forward Period & Commitment Period
Having divested virtually all of its generation, and not wanting to sign long-term purchase power agreements, Consolidated Edison Co. relies on the capacity market, said Richard Miller, director of energy markets policy. The company’s service territory straddles the New York border with New Jersey and Pennsylvania, giving it experience with both NYISO and PJM.
Miller noted that PJM, which purchases capacity three years in advance, has attracted more than 4,000 MW of new generation in each of the last two auctions (more than 3.5% of the forecast peak), while the NYISO, which has a 6-month forward, has added less than 675 MW (1.7%).
Although PJM primarily acquires capacity for a one-year commitment period, some new resources can lock-in prices for three years.
But Analyst Julien Dumoulin-Smith, of UBS Investment Research said even three years is a “mismatch” with the long life of new generation, noting that California is “trending to a 10-year market.”
Todd Snitchler, chairman of the Public Utilities Commission of Ohio, said bankers told his agency “Five to seven years [commitment] … would make it much more economical to get new generation.”
Robert Erwin, general counsel of the Maryland Public Service Commission, said the short commitment period exacerbates’ bankers concern over the volatility of capacity prices. Bankers have told the PSC: “There’s no way I’m going to lend money on that kind of price signal – and certainly not for one year [of guaranteed revenue].”
Demand Response vs. ‘Steel in the Ground’
The role of demand response was another issue that sparked much discussion.
“It is simply not the case that 1 MW of Demand Response provides the same reliability contribution to the grid as 1 MW of steel in the ground,” said Shahid Malik, president of PSEG Energy Resources and Trade.
James Holodak, vice president of regulatory strategy and integrated analytics for National Grid USA, agreed, bemoaning demand response, which is not subject to must-offer rules, “jumping in and out of the market.”
Andy Ott, PJM executive vice president for markets, said PJM is seeking to treat demand response more as an operational resource reflecting differences in physical characteristics, as is the case with generators. He noted that most of the 14,000 MW of demand response that cleared in the most recent base auction gets two-hour notice and an identical price. “We can’t sustain that,” he said. “We really need to have more diversity.”
“Iron in the ground is worthless,” said Peter Cramton, professor of economics at the University of Maryland. “What consumers should be buying is energy in shortage situations.” He called for an ex-post grading of resources — a “second settlement” — with good performers receiving bonuses and penalties for poor performers.
Dan Curran, market strategist with demand response aggregator EnerNOC, said the “downstream” focus on demand response “is treating the symptom and not the cause.” He said it was more appropriate to set qualifications for participation in DR, as PJM is considering.
Tranches
The commission asked the panelists for their opinion on creating “tranches” of capacity products based on operational characteristics such as fast-ramping or load-following ability given the increase in variable and intermittent resources.
Michael Hogan, of the Regulatory Assistance Project, is a supporter, saying tranches would create a fairer and more efficient market. “We’ve had ObamaCare in energy for years…,” he said. “People are paying for insurance they don’t need for a service they don’t really consume.”
But Cramton called the idea “a nightmare” that would lead to “rent-seeking.”
Sue Kelly, general counsel of the American Public Power Association, also said she feared that tranches would lead to gaming. “There’s always an extremely enterprising financial player who will find a way to arbitrage,” she said.
Consultant James Wilson urged a “purist” view: “Stay focused on the peak day… rather than [making] it more complicated through ramping … or tranches.”
The Markets and Reliability Committee heard first reading last week on the following manual changes. Members will be asked to endorse the changes at the MRC’s next meeting.
WASHINGTON — Some came to praise PJM’s Reliability Pricing Model. Others said they’d like to bury it.
Six years after RPM’s inception, the Federal Energy Regulatory Commission convened a technical conference last week to ask the question: How’s the capacity market working for you?
The commission said it was time for a broad look at the strengths and weaknesses of PJM’s model and those launched later in ISO New England and NYISO and how the markets should evolve in the future. Commissioner Tony Clark likened the session to a “checkup.”
The day-long session, which featured 26 panelists and attracted an overflow crowd of hundreds, was the prelude for a potential FERC rulemaking. (The speakers’ written testimony is available in FERC’s eLibrary under Docket # AD13-7.)
PJM Represents `Best Practices’
Capacity Clearing Prices – Delivery Years 2006-2017 (Source: FERC)
The consensus among the speakers was that PJM’s market deserved the highest marks. “PJM does represent the vast majority of best practices here,” said securities analyst Julien Dumoulin-Smith of UBS Investment Research. Lee Davis, who heads NRG Energy’s operations in the three eastern regions, said his company is investing “hundreds of millions” to upgrade 600 MW of generation in PJM because of its confidence in the RTO. In contrast, he said, the company is retiring capacity in New England because of the instability in the region’s market rules. “We look at risk just as highly as we look at revenues,” he said.
Changes Needed
That’s not to say PJM’s model couldn’t use improvement, even its supporters acknowledged.
Andy Ott, PJM executive vice president for markets, cited concerns about the volume of imports that cleared in this year’s auction (see PJM Seeks to Curb Capacity Auction Speculation). He also cited price volatility in western PJM due to MISO’s “inadequate construct.”
Compromises Weaken Model
Consultant Roy Shanker said “FERC got it right” in setting capacity market rules but that compromises have eroded the construct. He cited PJM’s short-term resource procurement — which removes 2.5% of the reliability requirement from the demand curve — as “blatant price discrimination.”
There also was debate about the optimal forward and commitment periods, the role of demand response, the wisdom of creating “tranches” to reflect differences in resource capabilities and how capacity can accommodate the growing role of variable resources and new technologies such as storage. (See sidebar, Old Issues, New Technologies in Capacity Debate)
States, Public Power Bash MOPR
The central debate, however, was a crossfire between those who contend capacity prices are too high and those who say they are too low.
State and public power representatives said the markets interfere with state policies and have failed to attract competitively-priced new generation.
“A capacity market that does not recognize new capacity developed pursuant to the requirements of state statutes and regulations … cannot endure,” said Jeffrey Bentz, of the New England States Committee on Electricity.
Reality on the Ground
James Jablonski, representing the Public Power Association of New Jersey, said PJM’s capacity market rules don’t recognize “the reality on the ground.”
Despite capacity prices of $245 per MW Day in PSEG North, Jablonski said, no generation is being built because of the difficulty siting in the densely-populated state. “There’s no point in having … customers paying for something that doesn’t have a way of getting built.”
Ed Tatum, vice president of RTO and regulatory affairs for Old Dominion Electric Cooperative, said PJM’s rules to curb buyer-side market power are unnecessary. “I would like us to stop looking behind every tree for the boogeyman of monopsony power,” he said. “You have to think about intent [to exercise market power]. You have to think about incentives. You have to think about ability.”
He noted that PJM’s minimum price floor for generation sponsored by public power — the net Cost of New Entry (CONE) — has almost doubled since it was instituted.
Jablonski urged a return to the self-supply provisions in the 2006 RPM settlement. “We don’t bother you, you don’t bother us…We know we can build for less than [net CONE] so it makes no sense to buy from the capacity market.”
Generation Owners Cry Foul
Representatives of generation owners, however, said capacity prices are too low, due in part to state-subsidized generation projects in Maryland and New Jersey. Shahid Malik, president of PSEG Energy Resources and Trade, said his company decided against building a merchant generator because of concerns it would be undercut by a subsidized competitor.
William Massey, now counsel to COMPETE, a coalition of generators and others, said Maryland’s “contract for differences” with Competitive Power Ventures’ 725 MW St. Charles generating plant “skews the capacity market in a way that this commission should not allow.”
“That’s just not true,” Robert Erwin, general counsel of the Maryland Public Service Commission, shot back. He said Maryland’s initiative “irons out” volatility. “No one knows whether at the end of 20 years Maryland ratepayers will pay CPV or if CPV will have paid Maryland ratepayers.”
Commissioner LaFleur asked if the impact of state programs such as Maryland isn’t the same in reducing prices, even if it is not the state’s intent.
Erwin conceded its new generation could depress prices. “But it’s no different than a state that says we’re going to have emission limits on power plants,” which would have the opposite effect, he said.
Capacity Market Not Voluntary
Susan Kelly, general counsel of the American Public Power Association, parried with Commission Chairman Jon Wellinghoff, who said APPA’s members were not required to join RTOs and thus participate in capacity markets. “It’s not a legal requirement,” Wellinghoff said.
Kelly responded: “If you have to take transmission service from the organization it’s kind of silly not to be a member… no system can be an island.”
FERC’s Next Step
Some panelists said they hoped the conference would be a prelude to a future rulemaking.
Consultant Susan Tierney called for a policy statement — “a visioning thing” — on the role of capacity markets in the future.
Richard Miller, director of the energy markets policy at Consolidated Edison Co. called on the commission to impose “some minimum level of standardization.”
Others said the role of the capacity market should shrink to its initial concept — a “residual” role that supplements bilateral contracts and self-supply.
“The mother of all rulemakings – Standard Capacity Market Design – scares me,” said Kelly.
“I guarantee that’s not what it would be called,” responded LaFleur, prompting laughter from the audience.
LaFleur added: “There is not a `thing’ to be named. We have to distill what we learned.”
The following issues were approved by the Markets and Reliability and Members committees Thursday with little discussion. Each item is listed by agenda number, followed by a summary of the issue and links to prior coverage in RTO Insider.
Markets and Reliability Committee
2. PJM MANUALS
Members endorsed manual changes implementing PJM’s revised black start procedures (see FERC Docket ER13-1911). The changes affect M27 Section 7 and M12 Section 4.6.
Members endorsed changes to Manual 01: Control Center and Data Exchange Requirements to incorporate updated telemetry and EOP requirements.
3. COORDINATED TRANSACTION SCHEDULING
Members approved a new scheduling product intended to reduce uneconomic power flows between PJM and NYISO.
The Market Implementation Committee on Sept. 11 approved the Coordinated Transaction Scheduling product after amending it to address member concerns about the reliability of PJM’s price projection algorithm — on which CTS trades will be based.
The revised proposal would allow CTS to begin no sooner than September 2014 — later if MRC is not satisfied with the accuracy of the forecasts generated by PJM’s Intermediate Term Security Constrained Economic Dispatch (IT SCED) application.
The committee approved a proposal introduced by Dave Pratzon, of GT Power Group, (Package B) after the Operating Committee selected it over a proposal from PJM and the Market Monitor (Package A).
Pratzon said his proposal was tougher than the current penalty but less severe than the PJM-Market Monitor proposal, which he called overly punitive.
Members approved new rules to protect wind generators from being assigned artificially depressed capacity values due to curtailments ordered by PJM.
Under current policy, when wind generators are curtailed by PJM for any portion of a peak summer hour (2-6 p.m.), the entire hour is excluded from the generator’s capacity calculation.
The MRC selected Alternative 2 under which state estimator data would be used to interpolate output for each five-minute period with curtailments.
6. EFFICIENCY OF DEMAND RESPONSE REGISTRATION PROCESS
Members approved two proposals to streamline the demand response registration process.
Current rules require curtailment service providers to submit customer names to both the electric distribution company and load serving entity.
The MRC approved the following changes:
Emergency Registration: The LSE will be removed from the review and notification process; EDCs will continue to do reviews under “Relevant Electric Retail Regulatory Authority” rules.
Economic Registration: The LSE will remain involved but PJM will make administrative changes to simplify the review process. The EDC and LSE review process will be separated to eliminate unnecessary reviews.
The changes are motivated in part by FERC Order 745, which reduced the LSE’s role in the registration process.
7. ENERGY MARKET UP-LIFT SENIOR TASK FORCE (EMUSTF) CHARTER
Members approved the charter for the Energy Market Uplift Senior Task Force (EMUSTF). The MRC approved the creation of the task force in May to take a broad review of its method of providing Operating Reserve payments.
PJM said the changes were needed to reduce growing uplift costs resulting from Operating Reserves, “make whole” payments that ensure generators dispatched out of merit for system reliability don’t operate at a loss.
Constraints that can be quickly and cheaply resolved would be included in the Regional Transmission Expansion Plan (RTEP) under a proposal approved by the MC.
The new rules require PJM staff to identify — before posting the planning parameters for each Base Residual Auction — Locational Deliverability Areas in which the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity Emergency Transfer Objective.
Upgrades that raise the ratio above 1.15 would be added to the RTEP if they cost less than $5 million and can be completed within 36 months or prior to June 1 of the Delivery Year. Projects that duplicate upgrades whose cost is already assigned to an interconnection customer would be excluded.
PJM will add new processes for generators seeking exemptions from operating parameters under Tariff changes endorsed by the MC.
The parameters are defaults for different types and sizes of generators, covering minimum run and down times, maximum daily and weekly starts and turn down ratios (Eco Max/Eco Min). They were initiated in 2008 to ensure lower make whole payments for generators whose entire offers were not covered by Locational Marginal Pricing revenues.
A proposal to allow intra-year switching to nodal pricing failed at the Members Committee Thursday, falling just short of the two-thirds vote needed for approval.
The proposal by retail marketer Direct Energy, which would have allowed a limited number of such switches monthly, was opposed by members who said it would create administrative problems for electric distribution companies (EDCs) and potential losses for Financial Transmission Rights holders. The sector-weighted vote was 3.3 in favor and 1.7 against, short of the 3.34 total needed for passage.
David Scarpignato, head of PJM regulatory affairs for Direct Energy, said the changes would allow retail marketers to offer more innovative products. He said it would not have significant impact on EDCs or other market participants because it would cap switches at to 5% of the EDC network service peak load.
The Members Committee in 2005 unanimously endorsed a Tariff change allowing the switch to nodal pricing. But after more than seven years under the new rules, all but 15% of PJM load is still using zonal pricing.
The rules give customers one chance a year to switch to nodal pricing, effective June 1 in alignment with the planning year. Customers must provide notice of their intention to switch by October or January depending on type of service.
Scarpignato said the annual window for switching has limited retail marketers’ ability to provide innovative products such as price responsive demand, which he said is most attractive to those with nodal pricing.
The current rules mean it can take a customer up to 17 months to make the switch after deciding to do so — “major barrier” to adoption, Scarpignato said.
Scarpignato said the change would also help reduce congestion costs across PJM and assist PJM operations, which has said it would like more “granular” dispatch of demand response resources. Under the current zonal dispatch, Scarpignato said, “some of the DR in that zone is actually hurting” PJM’s attempts to relieve constraints.
Scarpignato’s argument won support from representatives for Old Dominion Electric Cooperative and Dominion, as well as from Howard Haas of Monitoring Analytics, PJM’s independent Market Monitor. “Nodal pricing is the way to go,” Haas said. “Unequivocally it is the way to go.”
Representatives from Exelon Corp. and Pepco Holdings spoke in opposition.
Jason Barker, of Exelon, said his company saw little “utility” to allowing intra-year switching and significant financial risk to the remaining zonal customers, who could see their costs increase.
“As the operator of three EDCs we do see substantial downside,” he said. “We’re disappointed that it’s come before the Members Committee after being roundly defeated at the MIC.”
Gloria Godson, of Pepco, said the change would be a “significant burden” on EDCs. “We will have to add additional staff to manage this.”
Scarpignato said the intra-year switches would have minimal financial impact on FTR holders and others in the zone. He said new customers connect to the grid year-round without major impacts.
In answer to a question from Godson, PJM’s Tom Zadlo said the change could impact FTRS. “It is potentially possible that there are some impacts on FTRs but it’s impossible to quantify.” The impact would depend on the size of the loads that switched, he said.
Marji Philips, representing Hess Corp., said economists’ preference for nodal pricing is similar to their support for energy–only markets in lieu of a capacity market. “It’s good in theory. As a practical reality it stinks.”
Philips said that PJM’s hedging tools are based on zones and hubs. If many customers switch to nodal pricing in mid-year, she said, it could create “ghettos” where customers will have to pay more of a risk premium because suppliers can’t hedge their loads.
Fourteen of 16 public power members voting supported the change along with three-quarters of 20 other suppliers and all eight end use customers. Transmission companies voted 7-2 against while generation owners split 5-5.
Scarpignato said after the meeting that his company was not giving up. “It was an extremely close vote,” he said. “We’re considering our options.”
