PJM and MISO have reached agreement on a new product for interchange transactions similar to the Coordinated Transaction Scheduling (CTS) product PJM launched Nov. 4 with NYISO.
The product is intended to reduce uneconomic flows between PJM and its western neighbor. PJM says almost half of the transactions from PJM into MISO occur when prices are higher in PJM.
Under CTS, traders would be able to submit “price differential” bids that would clear when the price difference between MISO and PJM exceeded a threshold set by the bidder.
PJM outlined its plan to the Market Implementation Committee Friday.
The new product will be in addition to two existing means of trading between the two RTOs: hourly evaluations of traditional wheel-through transactions and intra-hour evaluations of traditional LMP bids and offers. PJM and MISO will require CTS transactions to be submitted 75 minutes before the flow begins. Traditional transactions can be submitted only 20 minutes in advance.
“Market participants can still be a price taker if they feel they have a better idea of future prices than PJM,” said PJM’s Rebecca Carroll.
The CTS product is expected to be similar to the PJM-NYISO offering except that both PJM and MISO will evaluate the trades: only those trades that clear both PJM’s and MISO’s thresholds will clear. NYISO alone is responsible for clearing transactions for the original CTS product.
“Neither one of us [PJM and MISO] do an economic clearing today. We both need to make software changes,” Carroll explained.
PJM and MISO hope to obtain members’ approval in time for a filing with the Federal Energy Regulatory Commission in May 2015. Implementation may not occur until the third quarter of 2016 because of software changes required. “So we need a longer runway to get these software changes implemented,” Carroll said.
MISO’s Board of Directors Thursday rejected proposed guidelines on how the board chair makes committee appointments.
The guidelines, part of proposed changes to the Principles of Corporate Governance, were withdrawn after criticism from board members that they were “too prescriptive” and limited flexibility. The Corporate Governance & Strategic Planning Committee had earlier approved the changes by a 2-1 vote.
Some of the proposed changes spelled out the increase in the board’s membership to nine members from seven (in addition to the CEO), a change approved by the Federal Energy Regulatory Commission in June.
It was the guidelines proposed under the “Selection of Committee Members” that annoyed some directors. The guidelines spelled out the experience that should be required for membership on each of the board’s seven committees. One provision stated that membership on the nominating committee may be rotated annually.
“This is getting pretty prescriptive,” Director J. Michael Evans said. “I don’t think it’s ready for us to take up.”
The board referred the proposals back to the committee.
New Additions to MISO Board
Earlier in the day, MISO members elected two new directors: Thomas Rainwater, CEO of Rainwater Capital Management, and Paul Bonavia, executive chairman of UNS Energy, parent company of Tucson Electric Power and UniSource Energy Services.
One director is the first of two additions to the board between now and 2016 as it expands to nine members. The other takes the place of Shelley Longmuir, an attorney who had been on the board since 2006 but chose not to seek another term.
Baljit Dail, who has served on the board since 2009, was re-elected. All three will serve three-year terms.
The board is expanding from seven to eight directors effective January 1, 2015 and will add its ninth member in 2016.
Members also approved an increases in board members’ compensation. Annual retainers were increased by $10,000 to $70,000. The retainer for commission chairs was boosted by $2,500 to $7,500. The board chair also received a $2,500 increase to $15,000.
A day earlier, MISO’s Advisory Committee cast votes for new leadership. Vice Chairman Kevin Murray, executive director of the Industrial Energy Users-Ohio, was elected chairman for 2015. Tia Elliott, director of regulatory affairs for independent power producer NRG Energy, was elected vice chairman.
PJM’s Market Implementation Committee will begin work in January on an initiative to consider whether the RTO should be required to provide more notice to the market before introducing “closed loop” interfaces to capture operator actions in pricing.
The MIC last week approved an issue charge by DC Energy’s Bruce Bleiweis to consider if such pricing interfaces should be barred from taking effect until they are announced before the monthly Financial Transmission Rights or Balance of Planning Period FTR auction.
In the last year, PJM has created closed-loop interfaces in at least four locations so that operator actions — such as sub-zonal dispatch of demand response — are captured in LMPs rather than uplift. PJM said it must use the interfaces to set prices because its modeling software can only set prices for thermal constraints, not voltage problems.
Connecticut policymakers say inadequate natural gas infrastructure will lead to sharply higher electricity prices despite energy-efficiency measures that will nearly eliminate demand growth over the next decade.
The state’s 2014 Integrated Resource Plan, released last week by the Department of Energy and Environmental Protection, sees the state mirroring regional trends: an increased reliance on natural gas generation hampered by a constrained pipeline system, and shortfalls of capacity and renewable energy sources.
Increased prices for natural gas, capacity and renewable resources are likely to increase the generation rates for retail customers by 63%, from approximately 9.8 cents/kWh in 2014 to 16.0 cents/kWh in 2024.
“Connecticut ratepayers are being affected by critical developments in New England’s wholesale electricity markets that are challenging the affordability and reliability of the region’s electric system,” the plan says.
Demand growth is expected to be flat over the next decade due to the increased use of energy efficiency. Electricity consumption is only expected to grow by 0.05% annually, with peak demand growth at 0.5% annually. The state’s last IRP, in 2012, had projected an increase in consumption of approximately 1% per year.
Those efficiency gains will be offset, however, by several other factors, DEEP says:
New England’s capacity surplus will disappear by 2017, when a shortage of 143 MW is projected, primarily due to the announced retirement of 4,100 MW of non-gas generation. Capacity costs are likely to increase to about 4.9 cents/kWh by 2024, when the region will need an additional 1,700 MW in resources.
The state expressed skepticism about ISO-NE’s ability to fill the shortfall. “There has not been a shortage of capacity before to test the auction’s ability to attract new investment. ISO-NE has recently instituted major changes in the capacity market rules, which add to the department’s concern that the upcoming February 2015 auction may not attract the new capacity that is needed, driving up capacity prices and threatening system reliability. If the market fails, DEEP may pursue options within state authority to procure capacity resources, if needed.”
The region now depends on natural gas for more than half of its power generation, a situation that will be exacerbated by planned coal plant retirements and a shortage of pipeline capacity to deliver gas to both power plants and winter heating. “This problem is too big for any one state to solve alone, and all New England states should contribute to a solution,” the IRP says. Regional pipelines are seen as a potential solution, but local opposition that was especially loud in Massachusetts has put some initiatives on hold.
The wholesale spot market price of natural gas delivered to New England has spiked from about $1-3/MMBtu before 2012-13 to $8/MMBtu in 2012-13 and almost $14/MMBtu in 2013/14, adding $3 billion to wholesale electricity prices.
Gas pipeline capacity expansions expected to enter service in November 2016 as part of Connecticut’s Natural Gas Expansion Plan may provide only temporary relief, the plan says.
Competition between Connecticut and other states for a limited supply of new renewable resources will likely add 0.3 cents/kWh to retail rates by 2024. The impact would be larger but for long-term contracts signed with large wind, solar and biomass facilities, which will save ratepayers more than $235 million over the next two decades. These programs, including a solar incentive program and utility-owned renewables, will only provide about 2,400 GWh of renewable energy by 2020, or about 40% of Connecticut’s renewable portfolio standards goal of 20% by 2020. The plan calls for increased support for distributed generation to address the renewable shortfall.
The plan proposes using existing state authority to solicit large-scale hydropower to offset some natural gas generation, or seeking new authority from the legislature to run a competitive procurement process for liquefied natural gas (LNG) and gas pipeline capacity.
“Neither ISO-NE, the Federal Energy Regulatory Commission, nor key market actors such as electric generators or gas pipeline developers have proposed any meaningful market reforms that will cause electric market participants to invest in urgently needed, cost-effective gas pipeline infrastructure.”
The IRP notes a marked decrease in emissions since 2007, with NOx, SO2 and CO2 down 71%, 95% and 28%, respectively. But it said emissions will increase slightly as gas infrastructure constraints cause an increase in generation from the state’s remaining coal-fired capacity.
The plan also proposes “reviving and improving” state demand response programs if the D.C. Circuit Court of Appeals decision voiding federal jurisdiction over DR is not overturned by the Supreme Court.
The Federal Energy Regulatory Commission last week approved Duke Energy Progress’ $1.2 billion purchase of 700 MW of generation from the North Carolina Eastern Municipal Power Agency.
The deal will give Duke NCEMPA’s share of the Brunswick and Shearon Harris nuclear plants and the Mayo and Roxboro coal plants, generators that Duke jointly owned with NCEMPA.
Duke and NCEMPA agreed to the sale in late July and submitted it for FERC approval on Oct. 10. (See NCEMPA to Sell 700 MW of Generation to Duke.) There were no protests opposing the deal or comments asking for any conditions. In its order, the commission said it had no concerns about adverse effects on horizontal or vertical competition resulting from the deal.
The deal must still be approved by the Nuclear Regulatory Commission and regulators in North and South Carolina. Company officials are targeting to close in the third quarter of 2015.
According to Duke, NCEMPA members have accrued more than $2 billion in debt and its customers’ rates have increased since the 1980s. While FERC did not say whether it expected rates to go down, it found that rates would not be adversely affected by the deal. Duke will collect $343 million through rates, FERC said, but the company included a five-year hold-harmless commitment that it would not increase rates as part of the deal. NCEMPA members, and their customers, would still be on the hook for paying off the remaining debt, but the sale will significantly lessen it.
After breezing through regulatory approvals by Virginia and the Federal Energy Regulatory Commission, Exelon’s $6.8 billion acquisition of Pepco Holdings Inc. (PHI) is starting to run into some headwinds.
Citing doubts about Exelon’s claimed economic benefits, the staff of the Maryland Public Service Commission said the company should provide $167 million in credits to customers, an increase of two-thirds over the $100 million the company offered.
And last week, the Maryland Office of People’s Counsel urged the commission to reject the deal.
“There is no doubt that this acquisition is a boon to PHI shareholders, but it offers nothing to Maryland’s utility customers,” People’s Counsel Paula M. Carmody said. “While Exelon has provided a ‘checklist’ of purported benefits, including better reliability, to customers and the state, OPC has determined that they are either non-existent or woefully deficient.”
The Chicago-based energy giant still needs approval from Maryland, D.C., Delaware and New Jersey, in addition to the U.S. Department of Justice.
Like several groups that have filed comments with the PSC opposing the acquisition, Carmody is concerned about the size of the company that would result.
“Exelon already owns [Baltimore Gas and Electric], but this acquisition would allow Exelon … to control electric utilities serving 80% of Maryland’s electric customers,” she wrote. “Such an acquisition would allow Exelon to exercise undue influence and control over regulated electric service and retail electric company policies in most of the state of Maryland and much of the footprint in the PJM wholesale market area.”
Market power issues are at the forefront of other interveners’ concerns, including PJM’s Independent Market Monitor, Joe Bowring. Repeating concerns he expressed during the FERC approval process, Bowring said mitigation measures should be taken to keep the combined companies from exerting undue influence.
“The proposed merger raises potential vertical and horizontal market power issues,” Bowring wrote in a letter to the PSC last week.
Bowring recommended requiring the companies to agree to remain in PJM and to permit independent third-party interconnection studies. RTO Insider reported last week that the Department of Justice is investigating the interconnection process in PJM’s MAAC sub-region as part of its review of the merger. (See DOJ Probing Interconnection Process in Exelon-Pepco Merger.)
The Monitor also said Exelon should agree to a review of ratings of all elements of the combined transmission systems and a regular process for reviewing and updating transmission limits.
FERC approved the acquisition without requiring any of Bowring’s proposed mitigation measures. (See FERC Approves Exelon-Pepco Merger.)
Bruce Burcat, executive director of the Mid Atlantic Renewable Energy Coalition (MAREC), said that even mitigation measures wouldn’t keep Exelon from growing too powerful for the market.
“The size and scope of this merger in and of itself raises a lot of angst for MAREC as we are very troubled by the ability of this huge utility to dominate markets,” Burcat wrote the Maryland commission last week. “I am not sure that there is a sure way to completely mitigate or even anticipate the impacts … that the combination of these companies will present to regulators, competitors and most importantly ratepayers.”
Like many other groups, MAREC has also filed opposition briefs with regulatory agencies in D.C., Delaware and New Jersey.
While the Maryland PSC staff report didn’t urge rejection of the merger, it said that Exelon’s claims of economic benefits to the state was “deeply flawed” and said that the deal could result in job-loss impacts totaling up to $309 million.
In addition to the $100 million in customer credits, Exelon has promised to continue the charitable giving that Pepco did, to the tune of $50 million over the next 10 years.
Exelon spokesman Paul Adams acknowledged that not all parties are satisfied with what the company is offering but said the acquisition is a good deal for the entire territory.
“As part of this [PSC review] process, we are open to feedback and discussions with all stakeholders,” he said in a prepared statement. “We believe that the facts — which are available in the testimony we’ve filed with the commission and other information we have provided to the parties through the regulatory process — will show that this merger is in the public interest and will benefit customers and the community.”
Exelon has gathered some allies in Maryland. In October, the president of the Montgomery County Council, Craig L. Rice, wrote the PSC to say he believes that “the combination of these two companies is clearly in the public interest and will benefit Pepco customers, Montgomery County and the State of Maryland.”
Brien Poffenberger, CEO of the Maryland Chamber of Commerce, expressed his support in a letter published last week by The Baltimore Sun. “With so much at stake, it’s right that the Maryland Public Service Commission and other stakeholders take a hard look at what this merger will mean for consumers. But it’s also clear that Exelon has been a reliable partner, and it has the track record to prove it,” he wrote.
Hearings before the PSC are scheduled to begin Jan. 26. Hearings in New Jersey are set for Jan. 12. Both D.C. and Delaware have scheduled hearings for February.
Exelon withdrew its application for a water-quality permit for its Conowingo Hydroelectric Generating Station after state regulators indicated they would deny the permit.
Exelon said it will spend $3.5 million over the next two years to study the environmental consequences of sediments building up behind the Susquehanna River dam. The Maryland Department of the Environment had said it would deny the permit without more information about the sedimentation and its implications downstream in Chesapeake Bay. The department expects Exelon to reapply within three months.
The Federal Energy Regulatory Commission has already given Exelon a one-year operating license extension.
Dominion’s New Virginia Plant Goes into Operation on Schedule
The 1,329-MW Warren County Power Station, Dominion Virginia Power’s newest electric generating plant, went on line last week.
The $1.1 billion plant was completed on budget and on schedule, the company said last week. Construction began in March 2012. The natural gas-fired combined-cycle plant, just north of Front Royal, Va., has three combustion turbines, three heat-recovery steam generators and a steam turbine.
As a condition of its permits, Dominion agreed to close its coal-fired North Branch Power Station in West Virginia.
Duke Critic Launches TV Attack on Company’s Solar Record
NCWarn, an environmental and consumers’ rights group, has launched a series of satirical TV commercials slamming Duke Energy’s commitment to solar energy.
NCWarn Director Jim Warren said the ads are meant to show viewers that while Duke says it is a solar energy proponent, it really is trying to weaken the state’s solar energy rules to freeze out private solar development.
In response, Duke pointed out that the company plans to spend more than $500 million next year to build solar plants to meet a 2015 requirement that 6% of its retails sales are from renewable sources. The company has contracted to build or buy 278 MW of solar capacity in the coming year, helping push North Carolina to the third leading solar producer in the country. The North Carolina Utilities Commission approved the plan
“These projects will help provide significant amounts of cost-effective renewable energy to benefit our customers, comply with our state obligations and provide meaningful investments in the communities we serve,” said Rob Caldwell, the company’s senior vice president for distributed energy resources. By the end of 2015, Duke expects to produce or procure a total of 748 MW of solar capacity.
PPL’s Susquehanna Nuke Plant Shut Down by Water Leak
A water leak inside the containment structure surrounding the reactor at Susquehanna nuclear station Unit 1 prompted PPL employees to shut down the reactor, company officials said Saturday.
Although the leak was contained and did not pose a risk to the plant or human safety, the company decided to shut down the reactor and perform repairs as part of its winter readiness program. The company said it expected the repairs to be completed quickly.
Life sciences and materials company DSM opened a 6 MW solar facility at its manufacturing plant in Belvidere, N.J.
The solar panels are glazed with the company’s KhepriCoat coating that reduces sunlight reflection, improving energy production by up to 4%. The solar field was developed with GeoPeak and Marina Energy, and at peak production it will supply 30 to 40% of the plant’s energy needs.
Wetlands transmission line installation. (Source: Pepco Holdings Inc.)
Four companies vying for a contract to address stability problems at Artificial Island squared off in a tense PJM Transmission Expansion Advisory Committee meeting Dec. 9 before an unexpected crowd that required organizers to employ an overflow room.
The meeting had the atmosphere of a political debate as representatives from Transource Energy, LS Power and Dominion Resources delivered 30-minute presentations pitching their proposals. The fourth contestant, Public Service Electric & Gas, used its time to attack Dominion’s plan for using what it called untested technology.
PJM planners expect to present a final recommendation at the Jan. 8 TEAC meeting, in time for consideration by the Board of Managers in February, said Steve Herling, vice president for planning.
All of the potential solutions involve new transmission lines connecting Artificial Island, home to the Salem-Hope Creek nuclear complex, to Delaware.
LS Power and Transource are proposing a southern crossing of the Delaware River. Dominion and PSE&G are proposing a northern route with an overhead crossing. Both paths are expected to face permitting challenges, according to Paul McGlynn, general manager of system planning.
LS Power’s proposal includes both overhead and submarine options for the river crossing, each of which would carry a binding cost cap of $146 million.
“We are the only company that has offered PJM a significant cost cap,” LS Power Vice President Sharon Segner said. “We are taking on risks associated with real-estate costs, environmental mitigation costs, overhead/submarine river crossing costs and routing costs.”
She also touted her project’s proposed timeline of 42 months.
Transource emphasized its 50-50 partnership with Pepco Holdings Inc. and said its submarine proposal will have the easiest time obtaining permitting.
While it has not agreed to a cost cap, the company would forego 50% of any return-on-equity incentives on costs from $203 million to $255.3 million and all such incentives on any costs exceeding $255.3 million.
Ronnie Bailey, manager of transmission planning for Dominion, emphasized among his proposal’s advantages a 36- to 48-month turnaround time. The project’s cost of $164 million to $174 million also carries the least risk of cost overrun, he said.
Dominion’s solution combines thyristor controlled series compensation (TCSC) technology with static VAR compensators (SVCs) to ensure stability.
While a third-party study commissioned by PJM concluded Dominion’s model “proved stable for all critical faults,” according to McGlynn, the technology was widely challenged at the meeting.
PSE&G led the attack. Instead of speaking on their own proposal, PSE&G representatives used their half-hour to deliver a 25-slide presentation bashing Dominion’s plan as untested and unsafe.
PSE&G also cited criticism by its sister company, PSEG Nuclear, the operator of the Salem and Hope Creek plants.
“The use of the second-largest nuclear site in the U.S. as a test bed for a first-of-its-kind transmission design is problematic and presents potentially dire consequences,” PSEG Nuclear Vice President Christopher Schwarz said in written comments. “The potential consequences arising from a failure of the proposed design to provide both stability and SSR (sub-synchronous resonance) protection when called upon are simply unacceptable from a nuclear safety perspective.”
Dominion’s Bailey called such comments “misinformation” based on the performance of conventional capacitors, not the modern devices Dominion would use.
“The bottom line is these things work, and it’s been vetted by PJM,” he said. “TCSC is now an option to mitigate SSR, and it’s nothing to be afraid of.”
For its part, PSE&G has agreed to a cost cap of $221 million for its proposal, which faces siting hurdles in crossing protected wetland and wildlife areas in New Jersey. (See Two of Four Artificial Island Finalists Offer Cost Caps.)
PJM planners had recommended PSE&G’s selection for the project but re-engaged the other three companies after being widely criticized this summer by environmentalists, New Jersey officials and spurned bidders. (See PJM Puts the Brakes on Artificial Island Selection.)
The project is PJM’s first under the Federal Energy Regulatory Commission’s Order 1000, which opens up transmission line projects to non-incumbent companies.
Despite the hype, solar power still accounts for a fraction of U.S. electricity production, according a recent report by the Energy Information Administration.
The December 2014 Short-Term Energy Outlook estimates solar generation will make up only 0.6% of electricity generation in 2015. “While solar growth has historically been concentrated in customer-sited distributed generation installations, utility-scale solar capacity slightly more than doubled in 2013,” the EIA said.
“EIA expects that utility-scale solar capacity will nearly double again between the end of 2013 and the end of 2015, with about two-thirds of this new capacity being built in California.”
NRC Inspectors Find Radiation Monitoring Problems at Entergy’s Palisades Plant
Nuclear Regulatory Commission inspectors cited Entergy’s Palisades nuclear plant in Michigan for using an improper methodology to measure radiation levels that workers received during a refueling outage earlier this year.
An NRC spokesperson said no workers were overexposed, but proper procedures were not followed, constituting a safety violation. An Entergy spokesman said the company tried to use a new monitoring technology, but it was improperly implemented. The violation could result in increased oversight.
Midwest Railroad Coal Delivery Topic of FERC Panel Discussion
The Federal Energy Regulatory Commission will discuss concerns about the coming winter, coal stockpiles and railroad congestion at its meeting on Thursday.
Competition with shale-oil producers for railroad capacity has put pressure on timely deliveries of coal, causing worries that Midwest power plants may have trouble securing adequate coal deliveries this winter.
The meeting will feature a panel discussion with staffers from FERC and the Surface Transportation Board, as well as representatives from Minnesota Power, BNSF Railway and MISO.
The Senate voted 86-12 to confirm Democrats Ron Walter and Virginia Lodge to the Tennessee Valley Authority board. They will serve five-year terms on the nine-member board that oversees the TVA.
Walter, a television executive, and Lodge, a business consultant and former commissioner of the Tennessee Department of Human Services, are succeeding Barbara Haskew and Bill Sansom.
Walter and Lodge pledged to recuse themselves from any decisions involving TVA’s unfinished Bellefone Nuclear Plant. Both appointees had previous contacts with Chattanooga businessman Franklin Haney, who is advocating a private financing plan to complete the two-reactor plant in Alabama.
Department of Energy Issues $12.5B Nuclear Loan Program
The Department of Energy is offering $12.5 billion in loan guarantees for advanced nuclear energy projects that would reduce, avoid or sequester greenhouse gas emissions.
“This solicitation will help the U.S. build the next generation of safe and secure nuclear energy projects by providing the critical financing needed for innovations that have not been widely deployed at commercial scale in this country,” Energy Secretary Ernest Moniz said.
The Advanced Nuclear Energy Projects solicitation is one of four loan programs totaling $40 billion aimed at boosting low-carbon technologies. The other programs include $8 billion for fossil energy projects, $4 billion for renewable- and energy-efficiency projects and $16 billion for vehicle manufacturing.
The Federal Energy Regulatory Commission ranked fifth out of 25 mid-sized federal agencies in employee satisfaction and commitment, according to a survey of government agencies.
The nonprofit Partnership for Public Service gave FERC a 73.3 out of 100 in employee satisfaction and commitment, and a 77.5 in work-life balance. Only the Federal Deposit Insurance Corp., Government Accountability Office, Smithsonian Institution and Federal Trade Commission scored higher in the “2014 Best Places to Work in the Federal Government” survey.
FERC’s Office of General Counsel won the No. 1 spot among agency divisions with an 88.8.
PJM Market Monitor Joe Bowring said last week that the RTO should exclude supply-side stakeholders from participating in the drafting of cost development guidelines that determine generator compensation.
Bowring, speaking at PJM’s annual Market Monitoring Unit Advisory Committee meeting Friday, said he is contemplating a filing with the Federal Energy Regulatory Commission in 2015 to push for the change.
“It’s an accretion of things that have built up,” he said. “We are pretty unhappy [with the current rules]. We’re saying generators shouldn’t have an effective veto right” regarding changes.
The cost development guidelines, which govern compensation for generators receiving cost-based rates, are contained in PJM Manual 15.
Bowring acknowledged that the manual is subject to sector-weighted voting at the Markets and Reliability Committee and must also win approval from PJM’s Board of Managers — the only manual on which the board votes.
But he said the primary motion brought before the MRC is the result of a skewed process at the Cost Development Subcommittee, at which there is no sector-weighting and where generator representatives can overwhelm other stakeholder factions.
The MRC considers as a “primary” motion the proposed solution that receives the highest vote total at lower committees. Proposals that receive at least 50% support at the lower committee may be offered as secondary proposals if the primary proposal fails to win a two-thirds sector-weighted vote.
Bowring said he would attempt to win support for the change through the stakeholder process but wasn’t optimistic about the chances of success. He said a FERC filing would not come before the middle of 2015 because of other pressing matters, including a FERC filing on proposed changes to the calculation of lost opportunity costs, expected in January. (See p. 21 of the State of the Market report for the third quarter of 2014.)
Bowring’s proposal found no immediate support among stakeholders in attendance. “I can’t see changing the voting approaches without disenfranchising somebody somewhere,” said Dan Griffiths, executive director of the Consumer Advocates of PJM States.
John Horstmann of Dayton Power and Light noted that the Cost Development Subcommittee hasn’t held a meeting since October 2013. “I’m not sure I see the problem to the extent that you see it,” he said.
Disclosure of Market-Sensitive Information
Earlier in the meeting, Jeffrey Mayes, the Monitor’s general counsel, made a pitch for stakeholder support for protections against disclosure of confidential market-sensitive data through discovery in mergers and litigation.
Mayes said the Monitor had fought for tight restrictions on who could see data in the Exelon-Constellation merger and quashed a subpoena in a challenge to New Jersey’s Long Term Capacity Agreement Pilot program.
“If we hadn’t taken those steps [in the merger] almost everyone’s market information would have been made pretty public,” Bowring said.
Mayes said the Monitor’s position would be enhanced by explicit backing of PJM stakeholders.
“I would have been in a far better position if I could have a set of rules that had been worked out in advance and that members of the industry were behind,” Mayes said.
Mayes said PJM’s current rules “have a lot of process but not a lot of substance.” He said ISO-NE has a better definition than PJM of member confidentiality.
This proposal found a better reception among the members in attendance. “It certainly seems like something worth investigating,” said Dave Pratzon of GT Power Group, which represents generators.
PJM and MISO have reached agreement on a new product for interchange transactions similar to the Coordinated Transaction Scheduling (CTS) product PJM launched Nov. 4 with NYISO.
