Entergy announced Tuesday it will close its Pilgrim Nuclear Power Station in Plymouth, Mass., no later than June 1, 2019, marking the company’s exit from the New England market.
The company blamed “poor market conditions, reduced revenues and increased operational costs” for the planned closure. The plant has come under increased scrutiny from the Nuclear Regulatory Commission, having earned the second-worst ranking for operational performance. (See Federal Briefs.)
The company said it would cost $45 million to $60 million in direct costs, plus any additional capital expenses, to comply with NRC requirements.
(Source: Entergy)
“The decision to close Pilgrim was incredibly difficult because of the effect on our employees and the communities in which they work and live,” Entergy CEO Leo Denault said in a statement. “But market conditions and increased costs led us to reluctantly conclude that we had no option other than to shut down the plant.”
The 680-MW plant began operations in 1972.
The company blamed low current and forecast energy prices caused by shale gas. The Energy Information Administration reported last week that January 2016 forward contracts for on-peak power in New England are trading at about $90/MWh, versus $190/MWh a year ago.
Entergy says the falling prices would lower annual revenue from Pilgrim by more than $40 million.
It also blamed what it called “wholesale energy market design flaws” that suppress energy and capacity prices, state subsidies for renewable energy and a recent proposal to import Canadian hydropower. (See Baker: Hydropower Contracts Best Way to Lower Costs.)
The merchant plant was relicensed three years ago by NRC and can operate through 2032. But the commission’s decision to place Pilgrim in column 4 of the reactor oversight process action matrix put it in the unwelcome position of being one of three of the country’s 99 nuclear plants so designated.
“We have invested hundreds of millions of dollars to improve — first and foremost — Pilgrim’s safety, as well as its reliability and security, but face increased operational costs and enhanced Nuclear Regulatory Commission oversight,” the company said. “We also take into account the effect on our stakeholders of operating over the long-term if it is not economically viable to do so.” Entergy said the exact date for closing the plant would be decided in the first half of 2016. It already notified ISO-NE that the plant will not be available as a capacity resource starting in mid-2019.
ISO-NE’s 10th capacity commitment period begins in June 2019, with its Forward Capacity Auction slated for February 2016.
Generators are required to notify the RTO by Monday if they will participate in the 2016 auction.
Nuclear power generated 34% of New England’s power in 2014. Pilgrim represents almost 17% of the region’s nuclear capacity.
ISO-NE could ask Entergy to keep the plant online if a study indicates it is needed for grid reliability. If Entergy agrees, it would receive out-of-market payments. But the RTO does not have the authority to prevent a resource from retiring.
The closure of Pilgrim will mark Entergy’s exit from New England. The company closed the 615-MW Vermont Yankee nuclear power plant at the end of 2014 and last week announced the sale of a 583-MW natural gas plant in Rhode Island. (See Entergy Sees Big Gain on Sale of RI Gas Plant to Carlyle.)
The Pilgrim nuclear decommissioning trust had a balance of approximately $870 million as of Sept. 30, which is approximately $240 million above what NRC requires for license termination activities, Entergy said.
Entergy bought the plant in 1998 for $80 million from Boston Edison. Entergy Nuclear was the first company in the nation to purchase a nuclear plant through the competitive bid process, it said.
Exelon spokesman Paul Elsberg confirmed last week that the concessions the company agreed to in its bid to win D.C.’s approval of its takeover of Pepco Holdings Inc. could result in changes to the deals already struck with Delaware, Maryland and New Jersey.
“The most-favored-nations clauses in other jurisdictions that have already approved the merger proposal … would be triggered by a final order from the Public Service Commission of the District of Columbia approving the merger,” he said. “The existing approvals are not contingent on the result of the MFN, although once the D.C. PSC issued its order, we would return to the other commissions to true up our merger packages in their jurisdictions.”
Elsberg said the company did not have an estimate of how much the cascading concessions would cost.
Exelon and Pepco had estimated that accepting all of the district’s demands would have boosted the cost of the proposed transaction to $7.35 billion to $8.75 billion, according to the PSC’s Aug. 27 order rejecting the merger.
“That was the PSC’s estimate based on a different set of proposals, and not the settlement with the District of Columbia government,” Elsberg said. “Regrettably, we do not have an estimated cost based on the current settlement.”
In its settlement with D.C., Exelon pledged $72.8 million in a Customer Investment Fund (CIF), which the company says results in $215.94 in benefits per customer, based on 337,117 customers. The MFN provision, identical for each jurisdiction, requires that Exelon increase each jurisdiction’s CIF so that the benefits per distribution customer are equal.
Based on estimates of each jurisdiction’s number of residential customers, the settlement could increase Exelon’s total contribution to the CIFs by more than $100 million. (See chart.)
(Based on estimated number of customers in N.J., Del. and Md.)
Some state regulators, however, say they believe the MFN provisions applies to more than just the CIFs and include other benefits.
Roger Berliner, a regulatory attorney and Montgomery County councilman who led opposition to the merger in Maryland, said no amount of new benefits afforded his state would make it a deal that would be in the public interest.
But, he said, “Will I want to make sure if, in fact, there are things that have been offered to D.C. that should now be reflected in what Maryland consumers can get? Absolutely. I want everything we can get out of this.”
That includes the $5.2 million Exelon has offered for workforce training. “I promise we’ll be knocking on that door,” he said.
Delaware, as well, has its eyes on D.C.
“The plan all along was to have the commission review the settlements from all the jurisdictions regarding the most-favored-nation [status] and kind of see where we match up compared with what other jurisdictions got, so I think it’s potentially impacting Delaware,” PSC spokesman Matt Hartigan said. “Depending on what the final order says from D.C., that might result in more benefits, but it’s a little premature to say at this point.”
Stefanie Brand, director of the New Jersey Division of Rate Counsel, opposed the merger and still has concerns over issues like ratepayer protections and promises of reliability. But, she said, an approval in D.C. likely would mean more money for New Jersey customers.
“We don’t really know how it’s going to shake out,” she said.
On Aug. 25, D.C. People’s Counsel Sandra Mattavous-Frye hailed the Public Service Commission’s surprise rejection of the proposed Exelon-Pepco merger as a “David and Goliath” win.
Six weeks later, Mattavous-Frye stood with Exelon CEO Christopher Crane, urging the PSC to greenlight the $6.8 billion merger under an Oct. 6 settlement brokered by Mayor Muriel Bowser and Attorney General Karl Racine. Bowser and Racine also had previously opposed the deal.
What changed? “Affordability for consumers, reliability of service, renewable and sustainable energy options and jobs,” Mattavous-Frye told RTO Insider. “The concessions offered in the proposed settlement far exceed what was offered” in the original application, she said.
With the administration and public advocate on its side, Exelon’s chances appear to hinge on winning a ‘yes’ vote from PSC Chairman Betty Ann Kane or Commissioner Joanne Doddy Fort.
The third member of the panel, Commissioner Willie Phillips, had issued a partial dissent in August, saying that while he could not support the merger as filed, he was “disappointed in the loss of the many opportunities inherent in the proposed merger that could have achieved benefits for ratepayers, the local economy and the environment of the District of Columbia.”
The other commissioners also lamented having to rule without being offered a settlement that could have addressed critics’ concerns. “Therefore, we consider the joint application as it stands on this record, not as it might have been proposed,” the order said.
Done Deal?
That’s leading some to conclude the merger is likely to be approved.
“I think the settlement itself rather than what’s in the settlement makes it more likely” that the commission will approve it, said Anya Schoolman, president of solar power advocate group DC SUN, one of the few intervenors in the case who did not sign on to the agreement.
The PSC will hear comments through Oct. 16 on the motion by the D.C. government and the utilities to reopen the record to consider the settlement. The applicants have requested a decision within 150 days.
While Washingtonians debate whether Bowser’s decision to settle was savvy or a sell-out, the other states that approved the acquisition on a “most favored nation” status — Delaware, Maryland and New Jersey — are watching closely to see what a sweetened deal for the district will mean for them. (See related story, ‘Most Favored Nation’ Clause Triggered.)
Meanwhile, Wall Street is weighing both the odds the deal will be consummated and whether the additional concessions Exelon made significantly hurt the acquisition’s attractiveness. Exelon stock rose almost a dollar after the settlement was announced last week, closing Friday at $30.82. Pepco also rose almost a dollar, ending the week at $26.52.
The acquisition would create the Mid-Atlantic’s largest electric and gas utility — and the country’s largest utility by customer count. Exelon has said the deal would boost its customer base to nearly 9.8 million from 7.8 million and increase its rate base to almost $26 billion from $19 billion.
Exelon Concessions
In making its decision, the PSC said it weighed the proposal on seven factors of public interest, among them the effects on ratepayers and shareholders, market competition and preservation of natural resources and the environment. (See DC Halts Exelon’s Acquisition of Pepco Holdings; Pepco Stock Tumbles.)
Under the settlement, Exelon would invest $78 million in the district — more than five times Exelon’s initial pledge of $14 million — to promote sustainability, increase reliability and support low-income residents. (See sidebar, Details of Exelon-D.C. Settlement.)
Of that, $17 million would be put toward conserving natural resources and the environment and promoting energy efficiency.
Exelon also would set aside $25 million to offset rate increases through March 2019 and immediately disburse $14 million to customers.
Exelon and PHI have committed to moving 100 jobs to the district from elsewhere and hiring at least 102 union employees within two years while dedicating $5.2 million in workforce training for district residents.
D.C. Councilman Vincent Orange, speaking on the Kojo Nnamdi radio show Thursday, lauded Bowser’s office for securing the agreement.
“The mayor and her team actually entered into some intense negotiations and basically, they took us from last to first in terms of benefits that are going to be realized for the ratepayers and consumers in the District of Columbia,” said Orange, a former regional vice president for PHI.
‘Cheap Baubles’
“What they’ve offered is baubles — cheap, showy things that don’t really add up,” countered Councilwoman Mary Cheh. “The people who are getting a bad deal are residents and ratepayers.”
“We think that either the mayor got tricked into agreeing to a deal that provides very little more for D.C. than the rejected deal, or she is trying to trick us into believing that this is something substantially better,” said DC Sun’s Schoolman. “The bottom line is that this does not change the underlying conflict of interest” between Exelon as a merchant generator with a commitment to its nuclear fleet and the district’s push for renewable energy.
The other public interest group absent from the settlement is Grid 2.0, which advocates for distributed generation.
“The ‘Halloween candy’ that’s been added by the mayor to make this appear better doesn’t address the underlying issues identified by the Public Service Commission,” said Larry Martin of Grid 2.0.
That was Then, This is Now
Former opponents of the merger aren’t the only ones who seem to have executed an about-face.
Exelon and Pepco initially argued against implementing a host of conditions proposed by Bowser’s administration, calling them “extraordinary and inappropriate on a number of levels.”
D.C. Councilwoman Mary Cheh (left) and D.C. People’s Counsel Sandra Mattavous-Frye celebrate the ruling. The two now stand on opposite sides of the debate on the settlement.
In particular, they said, increasing the Customer Investment Fund would be too costly. The settlement reached last week more than doubles the CIF, from $33.75 million to $72.8 million.
Due to the most-favored-nation clauses, accepting the list of conditions initially proffered by the D.C. government would have boosted the cost of the proposed transaction to $7.35 billion to $8.75 billion, according to the PSC’s order.
In addition, Crane testified that Exelon was not willing to make the boards of PHI and PEPCO more “independent” because it “is simply not tenable given the nature of the transaction and the business in general.” He went on to say, “If these or similar conditions were attached to the merger approval, I could not recommend to my board that I close the deal.”
The settlement, however, does increase the independence of PHI and PEPCO in a variety of ways.
Pepco’s CEO will be a member of Exelon’s Executive Committee and will “have full authority to make rate case decisions,” the settlement said. “The district and Pepco will be anything but ‘second tier’ in the new organization.”
Asked what changed Crane’s mind, Exelon spokesman Paul Elsberg said, “Since the PSC explained why it didn’t approve the merger, we’ve been working hard to learn what’s most important to the district — and we’ve responded in the settlement with the District of Columbia government.
“This included as part of the overall settlement package commitments that strengthen PHI board independence.”
Businesses Support
Some of the most vocal supporters of the deal are the D.C. business community and charitable organizations that receive funding from Pepco. (See related story, Pepco’s Influence Runs Deep.)
Harry Wingo, president and CEO of the D.C. Chamber of Commerce, has supported the merger from the start and recently participated in a media blitz, including a video posted on the merger partners’ website.
Among other advantages, he said, the merger will give Pepco the ability to improve its infrastructure.
“I think the fact that the mayor is behind this improves the likelihood of this moving forward,” he said. “I’m excited about it being approved.”
James Dinegar, president of the Greater Washington Board of Trade, said the merger would improve reliability, safety and costs.
“Pepco has real challenges on reliability. Here is an opportunity to act like a real world power capital, not a city that has its power go out” frequently, he said, calling Exelon one of the best power companies in the country.
“My concern now is that if the best company can’t buy Pepco, no one can buy Pepco,” he said. If the commission rejects the merger, he said, D.C. would be left with a “wounded power company.”
“My patience is pretty well done with the opponents. … What’s your solution for reliability?”
Critics say Pepco is already facing financial penalties if it fails to improve its reliability.
Checks and Balances
One of the main concerns surrounding the original merger filing was accountability. How could the district trust that Exelon would hold true to its promises?
Mattavous-Frye said she’s satisfied that the new agreement contains the “checks and balances” needed to ensure the companies’ promises are kept.
She said a significant concession was Exelon’s agreement to use an annual measurement, rather than a three-year average, to gauge progress in improving reliability.
As she noted, reliability would be monitored on an annual basis. Exelon has agreed to open its books to the OPC and PSC. And “ring-fencing” protections have been strengthened, separating PHI’s finances from that of Exelon’s affiliates and assets, such as its nuclear business.
Still, critics point to unaddressed issues. Yes, Exelon says it will support solar installations, but, said Schoolman, nothing in the agreement speaks to what price D.C. will be charged for that energy. She said that the district currently pays above-market prices for the solar energy produced at Exelon’s project at Dunbar High School.
“Thus, this provision may actually inhibit solar development and cost D.C. taxpayers more than if private sector developers were in charge of the project,” she said.
Rates
Another squabbling point is rates. Exelon has set aside $25.6 million to offset the effect of any rate increases through March 2019. Then, however, it will begin recouping its costs with a guaranteed 5% return.
“It’s a shell game, really,” Cheh said. “They say they’re going to give us this total amount. When you actually look at it, it’s money that we’re going to be giving back to them.”
Mattavous-Frye, however, said that absent a merger, it’s likely that rate increases over the next four years would top Exelon’s proposed $72.8 million investment in the district.
“The settlement provides roughly five years to prepare for the ‘energy future’ through public education, deployment of energy efficiency programs, incorporating local solar and renewable energy and by developing local microgrids — all while D.C. ratepayers are ‘ring fenced’ from the financial impact of outside factors affecting Exelon’s utility operations,” she said.
“After 2019, certainly there will be changes, but the regulatory process of rate case investigations will remain, and Exelon-Pepco would be required to request that ‘ring-fencing’ provisions be removed or modified.”
One of the most striking provisions of the settlement is Exelon’s intention to establish D.C. as its co-headquarters with Chicago. The offices of Exelon Utilities will be moved from Philadelphia to D.C., where CEO Denis O’Brien would preside over the largest electricity distribution unit in the country. O’Brien chairs the Greater Philadelphia Chamber of Commerce.
Also moving to D.C. from Chicago would be the primary offices of Exelon’s chief financial officer, currently Jonathan “Jack” Thayer, and chief strategy officer, William Von Hoene Jr. Pepco Energy Services also would be relocated from Arlington, Va.
Most Watched Case
Generating comments from more than 3,000 individuals and organizations, the Exelon-Pepco merger has garnered more participation than any other issue in the PSC’s history of more than a century.
At the time of the PSC’s vote to reject the merger, Mattavous-Frye credited the public. Standing against the deal were 26 of the district’s 42 Advisory Neighborhood Commissions and half of the council.
“This was about consumer empowerment,” she said. “People did not think their participation would be meaningful, and it is.”
For her part, Cheh is hoping the public will rise again.
“I hope all the Advisory Neighborhood Commissions all come forth and say this settlement is bad. The community groups that took a position have to come back and say this is bad,” she said. “They really have to make their voice heard.”
PJM acknowledged last week that the cost allocation for its Artificial Island stability fix may “appear disproportionate” but said its hands are tied by cost allocation rules proposed by transmission owners and approved by FERC.
Because the project is considered a lower-voltage facility, the cost of LS Power’s plan to run a new 230-kV circuit from Salem, N.J., under the Delaware River to a new substation near the 230-kV corridor in Delaware is being allocated entirely using the solution-based distribution factor (DFAX) methodology.
In a filing Friday in response to complaints from the public service commissions of Delaware and Maryland, PJM acknowledged that the DFAX methodology, “although producing reasonable results in the overwhelming number of applications involving typical reliability upgrades, may result in cost allocations that appear disproportionate depending upon the projects evaluated and their unique attributes” (EL15-95).
If the project relied more heavily on regional facilities — for example, if PJM had instead chosen a 500-kV transmission line — “the cost allocation impact to the Delmarva transmission zone would have been significantly less,” PJM said.
“PJM does not take a position with respect to the ultimate propriety of the solution-based DFAX methodology as applied to this case,” PJM said, adding that the cost allocation methodology is part of the transmission rate design, which is “within the sole province of the PJM transmission owners.”
The TOs will be filing their own response to the complaint, PJM said.
In most cases where the DFAX methodology is applied, it reasonably identifies the beneficiaries judging by power flows, PJM said. “For example, a project which fixes a transmission overload in a given region will allow greater flows into that constrained region,” it said.
But the Artificial Island project isn’t a typical reliability-based upgrade. It’s a stability issue that affects the ability to perform maintenance on the connected transmission system from the Salem and Hope Creek nuclear plants. Therefore, system stability, not power flow, was the derived benefit.
PJM said violations requiring such work are rare.
“As a result, in analyzing this matter, the commission should take into account the unique ‘as applied’ nature of the complaint and not lose sight of all of those instances where solution-based DFAX, for more typical reliability-based violations, renders a result which is ‘roughly commensurate’ with the intended beneficiaries,” PJM said in the filing.
PJM said that regardless of cost allocation, it stood by its selection of the winning proposal, which was “based upon sound engineering judgment which analyzed the submitted projects on the basis of system performance, constructability and cost evaluations.” (See PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.)
MISO, Big Rivers Electric Corp. and Century Aluminum have reached a settlement over the disputed system support resource agreement for Big Rivers’ Coleman plant in Hawesville, Ky. The settlement was submitted for FERC approval Oct. 6 (ER14-292, ER14-294).
MISO filed the SSR agreement in November 2013 to keep Coleman units 1-3 running for reliability. In December 2012, Big Rivers had asked to shut down the three boilers due to the loss of its power purchase agreements with a Century Aluminum smelter, the utility’s largest customer.
MISO won FERC approval to terminate the SSR after eight months, saying a special protection scheme and a service agreement between MISO and Century for reliability coordination service rendered it unnecessary.
Under the settlement, MISO will charge Big Rivers $25,000, with 99.5% of that amount credited back to Big Rivers and the remaining 0.5% credited to Southern Indiana Gas and Electric Co. Under separate bilateral agreements, Big Rivers will allocate its credit — $24,875 — to Century Aluminum.
Century agreed to drop its claims regarding the SSR agreement other than its “ability to petition … for the development and construction of transmission upgrades as a feasible alternative to future SSR agreements [and] claims arising out of the prioritization of Century’s entitlement, if any, to amounts paid by MISO to Big Rivers in connection with the Coleman SSR agreement under separate bilateral agreements.”
VALLEY FORGE, Pa. — PJM staff is recommending a 27% winter reserve target, the same value adopted last year, as the RTO plans for generator maintenance.
The target is based on unit summer ratings and expressed as a percentage of the forecasted weekly peak load. It is derived from simulations of the 13-week winter period.
In coordinating generator maintenance schedules, operations will seek to preserve a 27% margin after removing planned outages. This margin is a guide and not an absolute requirement.
The Operating Committee will be asked to endorse the target at its Nov. 3 meeting.
PJM has scrapped a proposed change to rules on long-duration transmission outages over concerns that it may be too restrictive for legitimate outages that cannot be planned in advance.
The current rule — which aims to identify long-term outages for the annual financial transmission rights auction — requires that outages scheduled for longer than 30 days be reported by Feb. 1 of the prior planning year.
PJM had considered amending the rule to also apply to individual outages totaling more than 30 days within an eight-week period.
Instead, PJM will monitor to ensure no one is circumventing the 30-day rule by breaking up long outages into multiple notices, said PJM’s Simon Tam.
If activity is detected that appears to go against the spirit of the rule, PJM will work with the transmission owner and enlist the Independent Market Monitor as necessary.
Proposal Aims to Increase Training, Certification Compliance
The System Operations Subcommittee has reached consensus on a PJM proposal designed to increase compliance with training and certification requirements, said Glen Boyle, manager of system operator training. (See “PJM Moves to Tighten Training, Certification Requirements” in PJM Operating Committee Briefs.)
Boyle said the subcommittee agreed with a proposal PJM presented at its Sept. 30 meeting that would quantify a company’s non-compliance and set an escalating set of responses.
If an operator is out of compliance, the company liaison and its Members Committee representative would be notified. The company’s compliance score would be based on a count of operators and months out of compliance.
For example, a company with one operator out of compliance for two months and a second operator out of compliance for three months would have a compliance score of five.
A score of five would trigger a written warning from PJM’s legal department. If the company’s score remained at five or above the following month, it would be reported to FERC as a violation of the PJM Operating Agreement and Tariff.
PJM also would require that operators who are out of compliance not be permitted to work their shifts.
NORTH LITTLE ROCK, Ark. — Arkansas environmental and utility regulators began a dialogue with stakeholders on how to comply with the Environmental Protection Agency’s Clean Power Plan in an all-day workshop Friday at the state’s Department of Environmental Quality headquarters.
ADEQ and the state Public Service Commission gathered with a diverse group that included representatives from MISO and SPP, environmentalists, and trade groups. The group discussed their reactions to the carbon emission rule and how to create an efficient stakeholder process.
“The process is undefined,” said PSC Chairman Ted Thomas, “but that’s why we’re here today.”
“Engagement is very important to us,” ADEQ Director Becky Keogh said. “We want to engage with as many stakeholders as we can.”
ADEQ and the PSC have been charged by Arkansas Gov. Asa Hutchinson with crafting a strategy that takes into account carbon dioxide reductions already underway, maintaining the “remaining useful life” of the state’s power plants and “limiting the EPA’s opportunities for overreach and encroachment upon the state’s rights.”
Thomas and Keogh have met in recent weeks with EPA Administrator Gina McCarthy and Janet McCabe, the agency’s assistant air administrator. They have also attended meetings in other states to gain additional perspectives.
The state envisions a steering committee leading the strategic effort, with a policy committee and three subcommittees focused on those areas with the most impact: the economy, the environment and the electric grid.
EPA released its final rule in August, giving states until September 2016 to decide whether to submit a final plan or an initial strategy requesting a two-year time extension. States that fail to submit a plan by September 2018 could find themselves under a federally implemented plan.
Arkansas is among the states suing to block the rule, although it saw its CO2 reduction requirements eased from 44% in the draft rule to 36% in the final. The targets, which must be reached by 2030, are based on a 2005 baseline.
“We moved from a very difficult position to the middle of the pack,” Keogh said.
SPP’s Lanny Nickell, vice president of engineering, was among those urging the state to consider a request for a two-year delay.
“We respect a state’s right to litigate, but we also believe we have to develop something on a parallel path in case the litigation is not effective,” said Nickell, who’s been leading SPP’s CPP compliance effort. “I ask that Arkansas work with us early and often in the process. We have to prepare the grid for whatever happens. The earlier we get some sense of what’s being planned, the better off we’ll be.”
Representing the other RTO in the room, MISO’s David Boyd said, “We will try and assist the state in implementing plans, but timing is still a problem. We do see a lot of transmission infrastructure and gas infrastructure [needs] and issues with design and permitting.”
Both Nickell and Boyd recommended a regional, trading-ready approach.
“We think carbon trading is a good thing,” Nickell said. “Our studies have shown that compliance on a regional basis is more effective than state-by-state. If you have to do something, it’s a good way to go, and trading ready helps.”
“Think millions of dollars being on the table,” Boyd said. “If you want to be part of a liquid market, you need a partner to trade with.”
The group also discussed the CPP’s mass-based and rate-based alternatives. Rate-based goals represent CO2 emissions per unit of generation, while mass-based represents the total metric tons of CO2 emitted by affected sources for each state.
Nickell said SPP is still evaluating the two alternatives, but, he said, “It appears a mass-based approach seems less complex.”
“We want to keep our options open and let the markets tell us what energy prices will be moving forward,” Thomas said.
Business and industrial interests repeated their criticism of EPA and the rule. Andrew Parker, director of governmental affairs for the state’s Chamber of Commerce, said the rule exceeds EPA’s legal authority and warned of significant cost increases to consumers, “especially the elderly, poor and others on fixed incomes.”
Jordan Tinsley, counsel for the nonprofit Arkansas Electric Energy Consumers, complained that the rule would result in stranded assets.
“They are requiring us to demolish our trusty pickups that we’ve taken good care of all these years. They won’t let us trade them in, but we have to go out and buy a shiny Lamborghini,” he said. “We think it will be very bad policy to get rid of our functional, efficient [generators], without regard for lower-cost alternatives.”
Brent Stevenson, executive director of the trade group Arkansas Forest Paper Council, took a more bombastic approach.
“Three words,” he said, pausing before thundering, “Ouch. Stop. Enough!
“There’s a cost to the EPA’s rules. Energy is one of the top three costs in our industry, along with labor and materials. Guess where we make up those costs? [The CPP] costs me money, it costs North Little Rock money, it costs the people of Arkansas money. We believe this rule should be struck down by the courts, but we’re not confident that will happen.”
Sierra Club of Arkansas Director Glen Hooks took an opposing viewpoint.
“We view the CPP as an opportunity,” he said. “If we do it properly, we can seize the opportunity in a way that benefits Arkansas and its environment and citizens.”
Or, as Keogh said, paraphrasing the late Yogi Berra, “When we reach the fork in the road, we’ll take it.”
FERC last week granted renewable energy resources an exemption from buyer-side mitigation rules in New York’s installed capacity market, a change it said will help the state comply with federal carbon emission rules. The commission also exempted self-supply resources built by load-serving entities to meet their own ICAP obligations.
But the commission denied a request to excuse demand response and most other resources from the mitigation rules (EL15-64).
In May, the New York Public Service Commission, the New York Power Authority and the New York State Energy Research and Development Authority filed a complaint seeking to limit the application of the buyer-side market power mitigation rules to only new gas- or oil-fired simple and combined-cycle units that are 20 MW or greater — seeking an exemption for resources including renewables, controllable transmission lines, nuclear generators, DR and repowered generators.
FERC ruled Friday that NYISO can no longer apply “buyer-side market power mitigation rules to certain narrowly defined renewable and self-supply resources that have limited or no incentive and ability to exercise buyer-side market power to artificially suppress ICAP market prices.”
The complainants argued that wind and solar resources are inefficient tools for exercising buyer-side market power because they require long development lead times and incur much higher development costs. They also said their intermittency and lower capacity factors made it unlikely buyers could drive down capacity market prices.
FERC agreed but said NYISO should set a megawatt cap limiting the total amount of renewables eligible for the exemption. It directed the ISO to make a compliance filing implementing the cap and other changes in the order within 90 days.
The ISO had told FERC that it supports exempting intermittent renewable resources such as wind and solar that are eligible for New York’s renewable portfolio standard.
The commission denied exemptions for controllable transmission lines, nuclear plants and repowered plants. It also said the complainants had failed to support their request for a “blanket waiver” for DR.
Self-supply resources were allowed within “net-short and net-long thresholds,” similar to those the commission previously approved in PJM.
“A well-formulated self-supply exemption will allow a load-serving entity to procure a portfolio that best allows it to manage its assessment of the risks it faces and, as [the Large Public Power Council] contends, eliminates the risk of effectively requiring load-serving entities to pay twice for capacity in the event that a self-supplied resource does not clear the capacity market,” the commission said.
Commissioner Colette Honorable issued a concurring statement saying that the ruling will help New York comply with the Environmental Protection Agency’s Clean Power Plan.
“It is clear that New York will rely upon renewable resources, in part, to meet future Clean Power Plan emissions standards,” she said. “Actions taken by the commission today will support New York’s efforts to invest in renewable resources while protecting consumers.”
SPP staff will urge the Markets and Operations Policy Committee this week to recommend approval of just one of three interregional projects coming out of the SPP-MISO coordinated system plan (CSP) study. But even that project is a long shot because MISO has already decided against it.
SPP’s Brett Hooton told the Seams Steering Committee last week that staff is recommending approval of only the $18.5 million South Shreveport-Wallace Lake rebuild, an 11-mile, 138-kV project addressing area congestion. SPP says the project has a benefit-cost ratio of 11.86, assuming it pays 20% ($3.7 million), with the remainder paid by MISO.
Hooton said staff does not recommend the other two interregional projects evaluated as part of a regional review: the Alto-Swartz series reactor and the Elm Creek-NSUB 345-kV transmission line. He said both could be reevaluated in a future regional or interregional study.
Complicating matters, however, was MISO’s announcement before its Planning Advisory Committee last month that it would not recommend any of the three projects for approval to its board. Staff told the PAC it found all three projects’ costs outweighed the calculated benefits. MISO said the project showed a benefit-cost ratio of 0.86. (See “No Go for MISO-SPP Interregional Projects,” in MISO Planning Advisory Committee Briefs.)
The two RTOs face a December deadline to come to agreement on the interregional projects, though the current six-month window can be extended. MISO’s Board of Directors meets Dec. 10 and will take up staff’s recommendation on the interregional projects at that time.
“MISO can act or decide not to act,” said David Kelley, SPP’s director of interregional relations. “That will be a decision if MISO decides not to make a recommendation at all.”
Hooton told the SSC that MISO staff has been invited to present its study results at the Oct. 22 meeting of SPP’s Economic Studies Working Group, which has also endorsed the South Shreveport-Wallace Lake project. A MISO spokesperson said the RTO would participate in the conference call.
SPP’s review of the three projects took into account modeling updates since the CSP’s initial approval. These included transmission projects approved in January, updated generator information based on the 2017 Integrated Transmission Planning 10-year assessment and a new 500-kV MISO project to serve added industrial load in southern Louisiana.
MISO is evaluating alternatives to the Alto series reactor project for resolving local area congestion and reliability and transmission service needs in the market congestion planning study.
SPP Adds TO Members, Tie Lines with Integrated System
The Oct. 1 addition of the Integrated System has more than doubled SPP’s tie lines, from 233 to 498.
With the IS, SPP is now responsible for both DC ties from the Eastern Interconnection to ERCOT and seven DC ties to the Western Electricity Coordinating Council.
In addition to the system’s three main entities — Western Area Power Administration-Upper Great Plains, Basin Electric Power Cooperative and Heartland Consumers Power District — SPP added Basin Electric members Corn Belt Power Cooperative, East River Electric Power Cooperative and Northwest Iowa Power Cooperative.
Also coming aboard as TO members were NorthWestern Energy, Missouri River Energy Services and Harlan Municipal Utilities.
SPP now has 30 TO members. On Jan. 1, it will add two more when it picks up Basin Electric members Tri-State Generation and Transmission Association Cooperative and Central Power Electric Cooperative.
Tx Project Proposals Increase with Order 1000
SPP has seen a large increase in the number of transmission project proposals as a result of FERC Order 1000.
The RTO received more than 1,700 detailed project proposals in its last planning cycle as a part of its transmission-owner selection process, which allows for competitive bidding on certain transmission projects. SPP normally sees 300 to 400 proposals a cycle, according to Ben Bright, SPP’s manager of regulatory processes.
Bright told the Transmission Planning Improvement Task Force last week the sudden increase “creates a lot of churn and staff time,” but that SPP is working to improve the submittal forms and discussing other options to streamline the process. He said working with states on individual right-of-way issues has also added to staff’s workload.
“We’re expecting even more [proposals] this cycle,” Bright said.
Entergy has agreed to sell a Rhode Island natural gas-fired power plant to The Carlyle Group for $490 million, a 40% mark-up in less than four years.
Entergy acquired the 13-year-old Rhode Island State Energy Center in Johnston, R.I., from NextEra Energy Resources for $346 million in December 2011. Entergy increased the plant’s capacity from 550 MW to the current 583 MW.
“Our strategy for Entergy Wholesale Commodities is focused on being disciplined about reducing risk and freeing up financial resources for other opportunities,” Entergy CEO Leo Denault said in a statement. “RISEC has been a very good investment for us, and its sale is consistent with that strategy.”
Entergy expects to record a net gain of approximately 50 cents/share assuming closing of the sale occurs in the fourth quarter, it said.
Carlyle insists it is a good deal for it as well.
“RISEC is among the most efficient combined-cycle facilities in New England and is well-positioned to capitalize on strong regional market dynamics. New England represents an attractive market for investment due to its transparency and incentives for reliable generation,” Matt O’Connor, Carlyle managing director and co-head of Carlyle Power Partners, said in a statement. “Additionally, the retirement of aging generation in the region is putting a greater emphasis on efficient gas-fired generators, like RISEC, to meet everyday electricity demand.”
The purchase is being made through Carlyle’s portfolio company Cogentrix Energy Power Management. It increases its power generation portfolio to 18 power plants totaling more than 4,900 MW.
The plant is located in ISO-NE’s constrained Southeastern Massachusetts-Rhode Island capacity zone. The zone failed to meet its capacity requirement in February’s ninth Forward Capacity Auction, which led to the imposition of administrative pricing well above those of resources that cleared at auction. (See Prices up One-Third in ISO-NE Capacity Auction.)
The announcement comes just a few weeks after UBS Global Research downgraded Entergy to sell, based on the prospects for its wholesale commodities unit.
“After the latest disclosures of potential early retirements of Fitzpatrick [838 MW, in New York] and Pilgrim [688 MW, in Massachusetts], we are increasingly concerned about the unregulated plant value,” UBS wrote.
Entergy last month said it may close Pilgrim rather than begin expensive repairs required by the Nuclear Regulatory Commission. (See “NRC Downgrades Arkansas One, Pilgrim Nuclear Plants” in Federal Briefs.)
NRC twice in recent weeks announced deficiencies in the plant’s safety operations. (See “NRC Finds Pilgrim Station’s Weather Tower Inoperable” in Federal Briefs.)
