Entergy reported a third-quarter loss of $723 million (-$4.40/share) Nov. 2, primarily as a result of the decision to close its Pilgrim and FitzPatrick nuclear plants. The New Orleans-based company’s quarterly earnings compared unfavorably with its profit of $230 million ($1.27/share) a year earlier.
Entergy has announced plans to close both nuclear plants. It says neither plant can compete in the wholesale markets due to low power prices.
Operational earnings per share rose to $1.90 from $1.68, excluding the impairment charges. However, that was still below analysts’ projected earnings of $2/share, according to Thomson Reuters. Revenue fell 2.5%, from $3.46 billion in the prior-year quarter to $3.37 billion this year.
“We realize these numbers, while temporary, are disappointing,” said CEO Leo Denault during a conference call. “We remain focused on the long-term issues … and the best interests of our shareholders. In the near term, these decisions to close nuclear plants are very difficult to make, knowing the effect they have on our key stakeholders.”
Entergy updated its 2015 operational earnings guidance to $5.50 to $6.10/share, up from $5.10 to $5.90/share and more than analyst predictions of $5.30. The revised guidance reflects warmer weather and positive tax-benefit expectations, and lower fuel, refueling outage and depreciation and amortization expenses resulting from the nuclear impairments.
Offsetting that rosy outlook is Entergy’s sluggish growth in residential and industrial sales, the latter up 1.8%, far below the company’s original guidance of 4.4%.
“We’ve seen some new expansions at plants, but the ramp-ups are lower than expected,” said Theo Bunting, group president of utility operations. “We’ve seen lower volumes with our existing customers and some comeback in the petroleum-refining area in the third quarter, but we do have an existing customer going through an outage.”
Entergy executives said continued investments and favorable regulatory rulings in Arkansas and Texas remain key drivers for future growth. The company expects to close its acquisition of the Union Power Station and its four 495-MW, combined-cycle combustion turbines in southern Arkansas by year’s end.
“We need to get the Union deal done and resolve those regulatory actions,” said Executive Vice President and CFO Drew Marsh. “It’s important to get those investments into the rate base. Sales growth has been helpful, but it is really a lag.”
“We want to provide a glide path to a more consistent, predictable dividend growth,” Denault said. “In the past, we’ve taken a lumpy approach to it, raising the dividend 29 cents one year, taking a year off and then raising it 10 cents the next. Looking into the future, we hope to provide a consistent growth.”
Entergy stock closed at $68.55 after the earnings announcement, up 39 cents. However, its stock has been pummeled in 2015, losing 21.6% of its value since opening the year at $87.48.
Exelon has delayed for a year a decision on whether to mothball its Clinton reactor, the company said Thursday. CEO Chris Crane said the central Illinois plant will take part in MISO’s spring capacity auction, keeping the reactor functioning throughout the 2016/17 operating year.
The company’s decision was announced two days after MISO released a draft issues statement that acknowledged the need for design changes for retail choice states such as Illinois.
The company also cited the Illinois Power Agency’s capacity procurement for 2016 and the hope that its nuclear plants will receive a boost from the Environmental Protection Agency’s Clean Power Plan.
“We are encouraged by MISO’s statement and the potential for market reforms that are necessary to ensure long-term reliability in Southern Illinois,” Crane said in a statement. “However, the Clinton plant remains unprofitable and more needs to be done.”
MISO currently holds its auctions in March, less than three months in advance of the June 1 start of the operating year.
For restructured states such as Illinois, the issues statement acknowledged, “MISO’s resource adequacy construct may not provide a price signal sufficiently in advance” to incent new resources or to sustain investment in existing ones.
With baseload resources retiring due to environmental rules, the growth of renewables and low natural gas prices, it said “a market that solely delivers price signals reflecting short-term excess as is the case today may become insufficient” to ensure sufficient capacity, MISO said.
“While this may pose little challenge for states with a regulated framework for making new resource investment decisions, those that depend on market prices as the primary signal may become insufficiently served by the current MISO construct in future years.”
Price Formation
In addition to highlighting the shortcomings of the current schedule, the statement also cited “year-to-year volatility and the inability to efficiently recognize the marginal reliability value of incremental capacity resources” as problems. “As a result, the price signal produced may not suffice in the future as efficient or reliable enough to serve as an investment signal in a fully competitive retail market such as Illinois.”
At the Supply Adequacy Working Group meeting Oct. 29, Jeff Bladen, MISO’s executive director of market design, said it’s too early to have a timeline for solutions, and speculation on specific solutions is “premature.”
“We wouldn’t presume to know if this can be solved in two months, six months, nine months,” he said.
The issue is a top concern within the RTO; the meeting’s operator ran out of phone lines for stakeholders seeking to listen in remotely.
FERC’s MISO liaison, Chris Miller, told the Market Subcommittee earlier in the week that the commission has not set a schedule for any action it may take in response to the Oct. 20 technical conference.
“No word on what the commission’s going to do with that information just yet,” Miller said. Post-conference comments were due Nov. 4.
Nuclear Profitability
Last year, a Chicago Tribune financial analysis found Clinton was the least profitable last year among Exelon’s six Illinois nuclear plants, which the company says have suffered due to competition from low-cost natural gas and wind generation.
The Tribune said Clinton has earned below $29/MWh in recent years while the plant’s lone reactor requires between $45 and $55/MWh to meet operating costs.
Exelon has said that three of the six nuclear stations — Clinton, Quad Cities and Byron — are unprofitable.
The company cited the Illinois Environmental Protection Agency’s estimate that the loss of two Illinois nuclear power stations would more than double the emissions reductions required by the Clean Power Plan.
Exelon has requested that Illinois expand its clean energy subsidies to include nuclear power alongside wind and solar energy. Those critical of the Exelon subsidies have called them a nuclear “bailout” and said they would cost ratepayers around $300 million annually in surcharges. (See Exelon-Backed Bill Proposes Surcharge to Fund Illinois Nukes.)
Exelon says its year-long delay on Clinton will also give Illinois policymakers “more time to consider policy reforms and potential legislation that will level the playing field for all forms of carbon-free electricity.”
The 28-year-old Clinton generating station has a workforce of nearly 700 and is one of DeWitt County’s largest employers.
Entergy said Monday it will close the 838-MW James A. FitzPatrick Nuclear Power Plant near Syracuse, N.Y., in late 2016 or early 2017. The company blamed reduced plant revenues due to low natural gas prices, a market design that doesn’t compensate nuclear power for carbon-free emissions and high operational costs.
The decision, which was expected, was announced in conjunction with the company’s third-quarter earnings. Entergy had already announced it was taking a $1.6 billion impairment charge as it wrote down FitzPatrick and the Pilgrim nuclear plant in Massachusetts, which it is also closing. (See Entergy may Announce FitzPatrick’s Fate this Week.)
“Given the financial challenges our merchant power plants face from sustained wholesale power price declines and other unfavorable market conditions, we have been assessing each asset,” Entergy CEO Leo Denault said in a statement.
James A. Fitzpatrick Nuclear Power Plant (Source: Entergy)
“Entergy and New York state officials worked tirelessly over the past two months to reach a constructive and mutually beneficial agreement to avoid a shutdown but were unsuccessful,” he added. FitzPatrick, which has been operating since 1975, employs more than 600 workers.
Current and forecast power prices have fallen by about $10/MWh, costing FitzPatrick $60 million in annual revenue, the company said.
It also blamed a “flawed market design” that “fails to recognize or adequately compensate nuclear generators” for their fuel diversity and environmental benefits.
Like Pilgrim and Vermont Yankee, which Entergy closed in 2014, FitzPatrick has a high cost structure because it is a single unit. (See Entergy Closing Pilgrim Nuclear Power Station.)
Entergy said it has informed NYISO and the New York Public Service Commission that it will retire the plant at the end of the current fuel cycle. Under PSC rules, closure of units 80 MW or larger will prompt a reliability study for the affected region.
Unlike other areas in New York with either inadequate generation or constrained transmission, however, FitzPatrick is located where there is excess power supply. The plant is in Central New York Zone C, which has generating capacity of 6,650 MW to meet peak summer demand of about 2,574 MW, according to NYISO.
“We’ve had NYISO do analyses on whether FitzPatrick qualifies for a reliability-must-run agreement, and that most recent analysis says that it does not,” Bill Mohl, president of Entergy Wholesale Commodities, said on a call with financial analysts.
Entergy said the plant’s nuclear decommissioning trust had a balance of $729 million as of Sept. 30, $77 million more than the minimum for license termination, according to a Nuclear Regulatory Commission report earlier this year.
The trust is held by the New York Power Authority, which sold the plant to Entergy in 2000. The parties are discussing whether NYPA would transfer the decommissioning trust and the liability to Entergy or enter into a fixed-price decommissioning contract with Entergy for the amount in the trust.
With FitzPatrick’s closure, Entergy will have one generator in operation in New York state, the Indian Point Energy Center in Buchanan. Gov. Andrew Cuomo has said his preference is to close that facility due to its proximity to New York City.
Exelon’s proposed acquisition of Pepco Holdings Inc. has been re-energized by the D.C. Public Service Commission, which unanimously agreed to reopen the case and denied intervenor status to a group that wants to buy PHI’s district assets.
The companies also won approval of an expedited timeline for reconsideration, with closing briefs due Dec. 18.
On Oct. 30, regulators rejected a late request to intervene by D.C. Public Power, a newly formed advocacy group that has proposed to buy Pepco’s district holdings post-merger and create a non-profit utility. (See Group Proposes to Buy Pepco DC’s Assets.)
Overturf
“We are obviously disappointed with the PSC’s decision, and at this time we are evaluating our options and considering what’s next,” CEO Michael Overturf said.
Meanwhile, seven of the D.C. Council’s 13 members have sent a letter to the PSC adding their support to a settlement agreement brokered by Mayor Muriel Bowser’s administration that would offer the district $78 million in public benefits.
The letter, dated Oct. 16, was not posted to the PSC site until after the commissioners voted Oct. 28 to reopen the matter. Among the signers were council members Brianne Nadeau and Brandon Todd, who previously had expressed to the PSC their opposition to the deal.
Nadeau
Nadeau posted the letter to her website, saying she had “decided to support the proposed settlement, which addresses her original concerns by protecting ratepayers through early 2019, providing assistance for low-income citizens and including a commitment to expand solar and wind power along with millions to support additional renewable energy development.”
Neither the council nor the mayor has a formal role in the decision-making process. The three-member commission unanimously rejected the merger in August, ruling that it was not in the public interest. However, Commissioner Willie Phillips issued a partial dissent, saying he was “disappointed in the loss of the many opportunities” the merger could have brought the district. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.)
The acquisition already has been approved by FERC and regulators in Delaware, Maryland, New Jersey and Virginia. In Maryland, however, the Office of People’s Counsel is trying to get a court-ordered review of the PSC’s decision. That effort was joined by Attorney General Brian Frosh, who filed an amicus brief in Queen Anne’s County Circuit Court on Oct. 28.
In agreeing to reconsider the merger in the district, PSC Chairwoman Betty Ann Kane said, “We will be releasing more of the details of the process, but we are all committed to seeing that this proceeds in a manner that is open, that is transparent, that is fair and that gives the commission the information and the opportunity that it needs to make a decision on whether this proposal is in the public interest.”
While winning over a number of former critics, notably People’s Counsel Sandra Mattavous-Frye and Attorney General Karl Racine, the settlement failed to garner the support of intervenors representing environmental and green energy interests. They say the fundamental conflict between Exelon’s commitment to its merchant generation and the district’s move toward renewable energy — a concern cited by the PSC in its denial — remains.
Exelon and Pepco requested a 150-day timeline for consideration of the revised deal. If the acquisition doesn’t close by Dec. 31, Exelon must buy back $2.75 billion of debt it financed to pay for the takeover at $1.01 on the dollar, CEO Christopher Crane recently told Bloomberg. Meanwhile, the company is paying $10 million per month in interest on the bonds it sold in June.
Crane also said that Exelon might walk away from the deal if it is not approved within five months.
Power DC, a coalition of public interest groups opposed to the merger, expressed disappointment with the PSC’s decision to reconsider the merger and the approved timeline. It had asked the PSC to take until June 30 to provide ample time for public input. With more than 3,000 comments, the deal has attracted the most public participation of any issue in the PSC’s history of more than a century.
“Exelon’s latest settlement offer still does not address the fundamental conflicts of interest identified by the PSC when it rejected the merger in August,” Power DC said in a statement after the Oct. 28 vote. “We will continue to work tirelessly over the coming weeks to ensure that the people are protected from this bad deal for D.C.” (See Merger Opponents Question Pepco’s Tactics.)
Expectedly, PHI was pleased with the vote.
“The procedural schedule approved by the commission has reply briefs filed on Dec. 18, which would allow for the commission’s decision sometime in the first quarter of 2016,” said Myra Oppel, PHI’s vice president for regional communications. “The schedule affords all parties and the public a fair opportunity to present their positions and ensures that the commission has a complete record to render its decision.”
The New York Public Service Commission for the second time rejected a New York assemblyman’s attempt to force the disclosure of bidding information from the state’s generators (13-01288).
Assemblyman James Brennan
James Brennan (D-Brooklyn) had appealed Freedom of Information Law rulings by the Records Access Officer in 2014 and this year that deemed such information protected trade secrets. (See Generator Records Ruling Expected This Week.)
“Assembly member Brennan, however, fails to point to any new facts or circumstances that have developed over the past year which would warrant a departure from the 2014 appeal determination,” commission Secretary Kathleen Burgess wrote in a 26-page determination Tuesday.
Brennan had charged that the New York wholesale market was not competitive and that the bidding information filed by the state’s utilities, which is redacted in their filings, is available in other publicly available sources.
The Independent Power Producers of New York responded that information in the New York filings is incomplete and could be misinterpreted.
“A thorough review of those documents shows that the entities proved the existence of competition in the wholesale energy markets and that disclosure of the information at issue would cause substantial competitive injury to the entities participating in those markets,” Burgess wrote.
In a cover letter announcing the ruling, Burgess said she was directing PSC staff to share it with FERC and the NYISO Independent Market Monitor to “request their respective opinions as to whether release of the information at issue in this determination would result in substantial competitive injury to the market participants.”
Brennan in a statement on Wednesday indicated the ruling is not the last word. “It is disappointing that the Public Service Commission chooses to conceal what should be public records of New York’s utility industry. My office will continue to fight to bring sunshine to electricity prices in New York,” he said. “Authentic competition does not exist in New York electricity markets. Instead, the power producers benefit from an administered market where prices are set way above cost to allow massive profits. That is why the industry needs reform.”
IPPNY CEO Gavin Donohue said Wednesday that Brennan “neither appreciates the consumer benefits nor understands the mechanics” of New York’s uniform clearing price auctions.
“Keeping the financial and operational data of generators private is critical to ensuring competitive bids. If that data were to become public, a generator could use the information to determine how much it could raise its bids into the market and still remain below the bids of its competitors,” he said in a statement.
“That’s why the information in question is considered a trade secret. I’m sure that the assemblyman wouldn’t expect Coca-Cola to reveal its secret recipe or McDonald’s to divulge how it prepares its special sauce, but that’s exactly what he’s asking of the power sector. Fortunately, yesterday’s decision by the PSC secretary will protect consumers from a very poor course of action.”
The D.C. Public Service Commission on Wednesday voted to reopen the Exelon-Pepco Holdings Inc. merger case to consider a proposed settlement with Mayor Muriel Bowser’s administration. The commission also granted the companies’ requested expedited timeline, with closing briefs due Dec. 18.
“We will be releasing more of the details of the process, but we are all committed to seeing that this proceeds in a manner that is open, that is transparent, that is fair and that gives the commission the information and the opportunity that it needs to make a decision on whether this proposal is in the public interest,” said PSC Chairwoman Betty Ann Kane.
The commission unanimously rejected the $6.8 billion deal in August, after it had been approved by FERC and regulators in Delaware, Maryland, New Jersey and Virginia.
Bowser’s office, however, later brokered an agreement that won over principal critics, including People’s Counsel Sandra Mattavous-Frye and Attorney General Karl Racine, by offering the district $78 million in public benefits. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.)
The settlement failed to garner the support of intervenors representing environmental and green energy interests, who said the fundamental conflict of Exelon’s commitment to its merchant generation and the district’s move toward renewable energy remained.
The joint applicants requested a 150-day timeline for consideration of the revised deal. If the acquisition doesn’t close by Dec. 31, Exelon must buy back $2.75 billion of debt it financed to pay for the takeover at $1.01 on the dollar, CEO Christopher Crane recently told Bloomberg. Meanwhile, the company is paying $10 million per month in interest on the bonds it sold in June.
Crane also said that Exelon may walk away from the deal if it is not approved within five months.
Power DC, a coalition of public interest groups opposed to the merger, expressed disappointment with the PSC’s decision. It had asked the PSC take until June 30 to provide ample time for public input. Amassing more than 3,000 comments, the deal has attracted the most public participation of any issue in the PSC’s history of more than a century.
After Wednesday’s vote, the group said in a statement, “The residents and small businesses of D.C. are disappointed with the Public Service Commission’s decision to expedite the review of Exelon’s bid to buy Pepco. Exelon’s latest settlement offer still does not address the fundamental conflicts of interest identified by the PSC when it rejected the merger in August. We will continue to work tirelessly over the coming weeks to ensure that the people are protected from this bad deal for D.C.” (See Merger Opponents Question Pepco’s Tactics.)
“The procedural schedule approved by the commission has reply briefs filed on Dec. 18, which would allow for the commission’s decision sometime in the first quarter of 2016,” said Myra Oppel, PHI’s vice president for regional communications. “The schedule affords all parties and the public a fair opportunity to present their positions and ensures that the commission has a complete record to render its decision.”
Kane said that other related motions, including a request from D.C. Public Power to become an intervenor in the case, will be ruled on shortly. (See Group Proposes to Buy Pepco DC’s Assets.)
According to the timeline approved Wednesday, the filing deadlines are as follows:
Oct. 30: Settlement agreement and supporting testimony.
Nov. 6: Data requests to settling parties regarding settlement agreement and supporting testimony.
Nov. 13: Settling parties’ responses to data requests regarding settlement agreement and supporting testimony.
Nov. 17: Non-settling parties’ testimony.
Nov. 20: Data requests to non-settling parties regarding settlement agreement and supporting testimony.
Nov. 25: Non-settling parties’ response to data requests regarding settlement agreement and supporting testimony.
Dec. 2-3 and possibly Dec. 4: Public interest hearings.
WASHINGTON — For months, supporters and detractors of the Environmental Protection Agency’s Clean Power Plan have been debating whether the carbon reductions are too stringent or not tough enough; whether it will compromise reliability; whether it will save struggling nuclear power plants.
With Thursday’s publication of the rule in the Federal Register, another question took center stage, one whose answer could make the others academic: Does EPA have the legal authority to do what it did?
Twenty-six states gave their answer Friday, filing suit in the D.C. Circuit Court of Appeals to void the rule, which seeks to cut the power sector’s carbon emissions by 32% by 2030, compared with 2005 levels.
West Virginia and 23 other states — Alabama, Arizona, Arkansas, Colorado, Florida, Georgia, Indiana, Kansas, Kentucky, Louisiana, Michigan, Missouri, Montana, Nebraska, New Jersey, North Carolina, Ohio, South Carolina, South Dakota, Texas, Utah, Wisconsin and Wyoming — joined in one challenge while Oklahoma and North Dakota filed separate suits. Congressional Republicans have also vowed to push legislation preventing the plan from taking effect.
Fifteen other states, along with D.C. and New York City, are planning to intervene in support of EPA.
A senior EPA official and a panel of legal experts gave their own opinions at Infocast’s second Clean Power Plan Summit in Washington last week.
Best System of Emission Reduction
The Supreme Court ruled in 2007 that EPA had authority to regulate carbon dioxide. At issue is how EPA is attempting to do it, specifically how the agency defined the “best system of emission reduction (BSER),” the standard set in Section 111(d) of the Clean Air Act.
“The best system of emission reduction is a term of art in Section 111 [that] has been applied more than 60 times. And at bottom we did not undertake the process of answering that question any differently than we have in the past,” said Joseph Goffman, EPA associate assistant administrator and senior counsel.
The answer that EPA came up with — largely substituting coal-fired generation with natural gas and renewables — “amounted to assembling the information that we were getting back from states and utilities and stakeholders based on what they were already doing,” said Goffman, noting that nearly all states have energy efficiency programs and more than half have policies encouraging or requiring renewables.
“So we answered the question ‘What is BSER?’ in some ways by saying, ‘Keep doing what you’re already doing.’ Level the playing field so that everyone is doing some ensemble of those things.”
Impossible Standards for Coal Plants
Critics contend that the Clean Power Plan is based on a novel — and improper — interpretation of 111(d).
“While EPA has issued numerous rules under Section 111, it has never interpreted this section in this manner or this broadly,” said Allison Wood, an environmental and administrative law attorney with Hunton & Williams. “Are you allowed under the Clean Air Act to look beyond [the fence line] and think about the electric system as a whole? … The answer to that I would say is ‘no.’”
Peter Glaser, an energy and environmental lawyer with Troutman Sanders, noted that EPA added in the final rule something that was missing from the draft — national emission standards: 1,305 lbs/MWh for coal and oil plants and 771 lbs/MWh for natural gas plants.
“It’s something that [has been] in every single new source performance standard that EPA has ever done. The fact that they determined that they really want to have something like that in the final [rule] tells you that they were very nervous about the legal justification,” Glaser said. “The problem is that the rates they came up with are rates that obviously the sources in the category can’t meet. And that’s the whole point, actually. Coal plants are not supposed to be 1,305. It’s supposed to reduce generation or close.
“What EPA did is to say, ‘We’re not really regulating the sources in the categories; we’re regulating the owners of the sources.’ So owners can meet the standards by reducing the generation of their coal units and increasing the generation — or paying someone else — to increase generation of renewable resources. … Despite Congress having consistently resisted giving EPA authority to do cap-and-trade, that’s exactly what EPA has finalized here.”
Wood agreed. “Never before in the history of the Clean Air Act has a standard of performance … been based on ‘don’t run,’” she said. “There is not any coal plant in the world that can meet [the emissions standard]. The only way it can meet it is by not running.”
Shutting Plants Down
Panel moderator Kate Konschnik, director of the Harvard Environmental Policy Initiative, disagreed, saying that EPA has previously issued rules that “caused certain units to shut down.”
“In particular, that was squarely at issue in a D.C. Circuit case about the cement kiln industry in the 1970s — that one type of cement plant would cease to exist because of the standards,” she said.
Bob Sussman, an environmental and energy policy consultant and former EPA senior policy counsel, also saw the rule differently than the critics.
“I don’t think that 111(d) of the Clean Air Act is guaranteeing that every existing plant subject to a standard is going to be able to meet that standard and continue to operate. Indeed, the whole idea of 111(d) is to push the envelope on technology and emission reduction,” Sussman said.
“I think the important point here is that the term in the statute is ‘best system of emission reduction.’ It’s not ‘best emission-reduction technology achievable.’
‘System’ is a pretty big and [expansive] term. It doesn’t necessarily mean only hardware that can be installed at a plant site that would reduce emissions. Here EPA is defining ‘system’ in a way that reflects the interconnected nature of the electricity grid and I think that’s a very reasonable thing to do.”
Ann Weeks, senior counsel and legal director for the Clean Air Task Force, said the rule was “locking in” the industry’s displacement of coal-fired generation by cheaper natural gas.
“Could EPA have done more in this rule? Absolutely,” she said. “The rule is not really technology-forcing.”
Redundant Regulation?
Wood said the interpretation of BSER is not the only obstacle EPA will have to face in defending the rule.
“The other hurdle that EPA is going to have to get over is whether this source category can even be regulated under 111(d) of the Clean Air Act because of the fact that it is also regulated under Section 112 through the Mercury and Air Toxics Standards,” she said.
The rule’s fortunes in the D.C. Circuit may depend on which three judges are picked to hear the case. But observers on all sides of the issue expect the Supreme Court to have the last word. (See Former EPA Official: Clean Power Plan won’t Survive.)
Sussman predicted that conservative Justices Antonin Scalia, Clarence Thomas and Samuel Alito will find EPA’s interpretation of the rule unreasonable and liberals Ruth Bader Ginsburg, Stephen Breyer, Sonia Sotomayor and Elena Kagan to rule in the agency’s favor.
“I think in the end it will come down to what Chief Justice [John] Roberts thinks and what Justice [Anthony] Kennedy thinks,” he said.
In the court’s 5-4 ruling in Massachusetts v. Environmental Protection Agency, which established EPA’s authority to regulate CO2, Kennedy sided with the majority, while Roberts joined the minority.
The chief justice wrote a dissent that focused not on the merits of the case but on rejecting the legal standing of the coalition of government officials and environmental groups that sought to force the Bush administration to act.
EPA’s Goffman said the agency didn’t concern itself with handicapping the justices’ leanings when it was writing the rule. “I only think about it in terms of whether we have a solid legal case to make and we think we do,” he told RTO Insider after his remarks. “We think we’re on solid ground. We trust that ultimately the merits will speak for themselves.”
LITTLE ROCK, Ark. — Industry representatives and those that regulate or work with them gathered here last week to discuss the Clean Power Plan and its implications — primarily near-term uncertainty — for the industry.
Regional compliance or state-by-state? Mass based or rate based? Comply or resist?
One certainty, as FERC Commissioner Colette Honorable joked, is that the Clean Power Plan is “a job-security act for lawyers.”
Nancy Lange (Minn PUC), Andy Kellen (WPPI), Scott Weaver (AEP), Sandy Byrd (AECC) and Pam Kiely (EDF) at the Great Plains CPP Seminar.
More seriously, Honorable said, “I do believe it’s important to hear from all the parties.”
Three panels of industry insiders did just that during a seminar organized by the Great Plains Institute and the Bipartisan Policy Center, focused on the Clean Power Plan’s impact on the midcontinent states.
“It was a very useful day. We spent time on the same issues we’re thinking about right now in Iowa,” said Amy Christensen, an administrative law judge with the Iowa Utilities Board. “We’re living and breathing this right now. It’s helpful to hear other speakers talk about the same issues.”
‘Common Currency’
Ted Thomas, chairman of the Arkansas Public Service Commission, told RTO Insider he was particularly struck by comments from PJM Senior Economic Policy Advisor Paul Sotkiewicz on the rate- vs. mass-based issue and use of gas plants.
A rate-based plan caps the emissions of a state’s power fleet based on an average (CO2 tons/MWh). A mass-based plan caps the total tons of carbon the power sector can emit each year.
“With a mass-based program … you can bring in new gas units and set aside the allowances,” Sotkiewicz explained.
“The thing to me that needs more study is [Sotkiewicz’] thought that mass-based is more accommodating than rate-based, because you can’t use new gas units to manage down your rates,” Thomas said. “The rate[-based] stuff is so complicated. With mass, it’s just tons of emissions. You already have a common currency.”
“Under an emissions-rate regime, new gas [units] can’t be brought in. So why go with an emissions rate if you’re a coal-heavy state?” asked MISO’s Kari Bennett. “With mass-based, you can retire older units and bring in newer ones. It’s easier to facilitate load growth with mass-based approaches.”
Nancy Lange of the Minnesota Public Utilities Commission took a different viewpoint. “I don’t know of any states that have done enough analysis to show one [mass- or rate-based] is more preferable than the other,” she said.
Both MISO and SPP say the mass-based approach would make regional compliance, with trading of emission credits, easier to administer, helping coal-reliant states. SPP released a study in July that indicated a state-by-state compliance approach could result in nearly 40% higher costs than a regional approach.
“The prudent thing is to look at regional compliance,” Honorable said, citing the SPP study.
Costs
“If we’re going to be retiring a significant portion of the nation’s coal fleet, the only substantial winner will be natural gas,” said the Arkansas Electric Cooperative Corp.’s Sandy Byrd, vice president of public affairs and member services. “If there’s going to be a dash for gas, we’ll be building more combined cycles, transmission infrastructure … there will be a huge cost coming that wouldn’t be without the CPP. We need to ensure the consumers know it’s going to happen.”
Jim Hunter, representing the International Brotherhood of Electrical Workers, agreed with Byrd. “We’re betting on gas,” he said, “but when the price goes up — and it will — the price of electricity is going up, too.”
Leakage
The panels also discussed “leakage” and its implications on adding new generation.
The Clean Power Plan covers generators that began construction on or before Jan. 8, 2014. Plants built after then are subject to EPA’s new source performance standard, which limits carbon emissions to 1,000 lbs/MWh for new baseload gas-fired units, versus the 771-pound limit for existing gas plants.
For a state that adopted rate-based compliance but shifts added new plants, the mass-based limit would no longer be equal to the original emission-rate limit.
“It’s a fuzzy concept, as described by the EPA,” said Scott Weaver, manager of strategic analysis for American Electric Power. “I think it’s flawed. The [emission] rates for [new] gas units are less stringent, so you’re shifting emissions from existing units to new units.”
States must decide whether to pursue rate-based or mass-based plans by September 2016. (States can also ask for a two-year extension at that time.)
States that decide not to comply with the Clean Power Plan or submit inadequate plans will be subject to a federal plan.
“State plans make a lot of sense,” Lange said. “It’s important to have the flexibility of a state plan, given states want the control and to maintain flexibility on how a state should comply with the rule.”
LITTLE ROCK, Ark. — MISO’s Board of Directors voted last week to switch to a quarterly meeting schedule from its current every-other-month calendar, a change likely to also be adopted by the Advisory Committee.
The changes are the first to result from the RTO’s stakeholder process redesign, which is also expected to result in a reduction in the number of committees.
The board voted unanimously Thursday to switch to four open board meetings, with two strategic planning meetings scheduled in the summer and fall.
“The idea of going to four meetings is to get all of our obligations met. I think it’ll be a really productive way to move forward,” MISO CEO John Bear said.
Too Few?
However, board member Michael Evans said that the quarterly meeting schedule could be too little given the multitude of issues facing MISO.
“We’ve got a lot of balls in the air, a lot of moving parts,” Evans said. “If you miss one [meeting] it means you’re six months in between meetings. I’m concerned about losing the relationships between board meetings and losing continuity on the issues. I think we ought to let that percolate a little bit.”
Board member Thomas Rainwater said less frequent meetings would challenge the board to do more work between meetings and put the onus on the board members to work harder individually. He added that he couldn’t urge the Advisory Committee to meet less if he wasn’t willing to apply that to the board.
“I’m pleased to see the diversity of opinion on the board. I can be persuaded either way. I look at this as four governance meetings … and two really deep dive strategic meetings,” Rainwater said.
Despite Evans’ concerns, the new schedule passed without objection.
The board’s vote came a day after the Advisory Committee discussed — but took no action on — making a similar change.
Advisory Committee Chairman Gary Mathis said the committee should follow the board’s meeting schedule.
“We should continue meeting this way, face-to-face whenever the board meets,” he said. “If the board is considering changing their schedule, then we should follow suit. I think it’s important to match those up. As they go, we should go too.”
Streamlining the Organizational Chart
The Advisory Committee also discussed the stakeholder redesign. At the third redesign workshop in September, stakeholders tentatively identified eight committees that would be eliminated, with their duties assigned to other panels (see organizational chart). MISO’s straw proposal called for eliminating 10 committees.
Board members suggested that stakeholders’ simplified redesign might be in need of further simplification.
Board Chairman Judy Walsh urged the stakeholder process redesign team to combine some of their six desired outcomes. “If you have more than three priorities, you have none at all,” Walsh said.
Rainwater echoed Walsh’s advice to focus on three top priorities. “Let’s start with some small victories,” he said.
Board member Baljit “Bal” Dail asked that the stakeholder planning team respect the role of the board versus the role of management in creating the organizational model. He said sometimes stakeholders bring “hot topic” issues before the board that are better handled by MISO management.
“The board takes a ‘noses in, fingers out’ approach,” Dail told them.
Michigan Public Service Commissioner Sally Talberg said more discussion was needed on whether stakeholders should focus on high-level issues versus specifics that can quickly become complex and warrant multiple meetings. She added that MISO’s 2,000-page Tariff can lead to “endless tinkering.”
MISO stakeholders will develop final recommendations at a fourth workshop Nov. 3. The final proposal for redesign will go before the Advisory Committee on Dec. 9.
LITTLE ROCK, Ark. — MISO is cool and collected heading into the winter, staff told the Markets Committee of the Board of Directors on Wednesday.
Todd Ramey, vice president for system operations and market services, said the RTO has 146 GW of capacity available to serve the estimated winter peak of 104 GW.
The RTO was able to meet its all-time winter peak of 109.3 GW during the polar vortex on Jan 6, 2014, without directing any demand reductions.
Since then, MISO has taken steps to improve gas-electric coordination and provide more transparency on fuel supplies.
Ramey said MISO is looking into putting other winter readiness measures into place, including emergency pricing and seasonal assessments of resource adequacy. Last year, MISO won FERC approval to create two capability products to manage short-term variations in load. MISO hopes to implement the products in 2016.
Entergy reported a third-quarter loss of $723 million (-$4.40/share) Nov. 2, primarily as a result of the decision to close its Pilgrim and FitzPatrick nuclear plants. The New Orleans-based company’s quarterly earnings compared unfavorably with its profit of $230 million ($1.27/share) a year earlier.
