Duke Energy last week confirmed it plans to sell its international business, which has been bedeviled by drought and weak currency exchange rates, the company said as it announced its fourth-quarter earnings.
“The returns over the last two years are inconsistent with our commitment to investors to provide predictable, stable earnings and cash flows. We believe there will be demand for this international portfolio at a reasonable valuation. The proceeds will be used to strengthen our balance sheet and help fund growth in our core businesses,” CEO Lynn Good said on a call with analysts.
“We expect that a sale will be dilutive,” she said. “Nonetheless, the strategic exit significantly improves our risk profile and enhances our ability to generate more consistent earnings and cash flows over time.”
Good said it was too early to provide a timeline for the transaction, which involves facilities in Brazil, Chile and Central America. Year over year, the international business saw adjusted income of $225 million, down from $428 million in 2014. In reporting Duke’s third-quarter 2015 earnings in November, CFO Steve Young had predicted the division’s earnings to stabilize by the end of the year and show modest growth in 2016.
Net income for Duke for the fourth quarter was $477 million, compared with $97 million for the same quarter in 2014. For the full year, the company reported earnings of $2.8 billion, compared with $1.9 billion in 2014.
Earnings per share for the fourth quarter were 87 cents, up slightly from a year earlier. For 2015, earnings per share were $4.05, compared with $2.66 the previous year.
“Fourth-quarter adjusted results were supported by increased retail pricing and wholesale margins in the regulated business, helping to offset the impact of record mild December weather in the Carolinas,” the company said in a release.
Discussing the company’s overall strategy, Good said, “Our industry is undergoing transformation with new technologies, evolving customer expectations, increasingly impactful public policies and abundant low-cost natural gas. These factors will have a profound impact on our business in the years ahead and are informing our strategic investments. We are focusing our long-term strategy on our core domestic regulated businesses and our highly contracted renewables portfolio.”
She also noted that Duke has “taken what we learned from the Dan River spill in early 2014 and applied it throughout our organization to strengthen operational discipline and results.”
A near-term focus has been working through closing the company’s coal ash ponds.
“Our intent would be to seek recovery in connection with a general base rate increase, which … would be toward the latter part of this planning period,” she added.
Exelon has asked the D.C. Circuit Court of Appeals to overturn two FERC orders that reaffirmed the zero-price offer requirement in ISO-NE’s new entrant pricing rule (16-1042).
FERC last month again rejected complaints by Exelon and Calpine that the rule unreasonably suppresses capacity prices and discriminates against existing resources. The commission upheld the rule in January 2015 and denied rehearing last month. (See FERC Again Rejects Challenge to ISO-NE New Entry Pricing.) ISO-NE’s rule allows new resources to lock in their first-year clearing price for up to six subsequent delivery years by offering as a price taker with a price of zero.
Footprint Power’s planned 674-MW natural gas plant (R) cleared ISO-NE’s seventh Forward Capacity Auction in 2013. It will be built on the site of the coal- and oil-fired Salem Harbor Station (L) on Massachusetts’ North Shore. (Source: GE)
Exelon and Calpine argued that the rule creates a discriminatory two-tiered pricing scheme, with existing resources receiving lower prices than new ones if clearing prices fall in subsequent Forward Capacity Auctions.
The commission had acknowledged that the existence of the lock-in option “may result in lower capacity clearing prices” but said this was part of “a reasonable balance between incenting new entry through greater investor assurance and protecting consumers from very high prices.”
In the FCA 10 auction this month, capacity prices dropped for the first time in four years, as new resources more than offset generation retirements. (See Prices Down 26% in ISO-NE Capacity Auction.)
MILFORD, Mass. — Carbon dioxide emissions rose about 7% in New England last year as the loss of the Vermont Yankee nuclear plant increased fossil fuel generation, ISO-NE said last week.
CO2 emissions rose to just more than 30 million tons in 2015, up from 28 million tons in 2014, Patricio Silva, ISO-NE senior analyst for system planning, told the Planning Advisory Committee during its annual environmental update Wednesday. That reversed a trend that has seen carbon emissions fall from 32 million tons in 2012 to 31 million tons in 2013. The figures are based on EPA data.
A separate data set from ISO-NE, which runs through only 2014 and includes emissions from smaller power plants not counted by EPA, shows CO2 emissions had declined 26% from 2001 through 2014.
Entergy, which owns Vermont Yankee, also plans to shut the Pilgrim nuclear plant in Massachusetts no later than mid-2019. Its closure would leave New England with only three nuclear generators: the Seabrook plant in New Hampshire and the two-unit Millstone plant in Connecticut. (See Entergy Closing Pilgrim Nuclear Power Station.)
Ozone Standard
In addition to a discussion of the region’s carbon emissions, the meeting also touched on EPA’s stricter ozone standards. In a rule adopted in October, the standard was reduced to 70 parts per billion from the 75 ppb adopted in 2008.
“Rhode Island and most of Connecticut would be non-attainment for the 2015 ozone standard,” Silva said.
Preliminary 2013-2015 data, based on eight-hour concentrations, show southwestern Connecticut exceeds even the less strenuous standard, at 81 ppb or more. Rhode Island and the much of the rest of Connecticut fall into the 71 to 80 ppb range. The rest of New England meets the new standard at less than 70 ppb.
WASHINGTON — FERC said last week it is streamlining its rehearing orders and creating a dedicated legal team within the Office of General Counsel to handle them.
The group, housed in OGC’s Solicitor’s Office, will produce shorter orders focusing on new arguments raised by petitioners, rather than chronicling the history of the case and reiterating the commission’s positions on arguments addressed in the original rulings.
“We are hopeful that the creation of the rehearings group, coupled with the more streamlined approach to rehearing orders, will allow the commission to more efficiently process requests for rehearing, which in turn will further the public interest,” Deputy Solicitor Robert Kennedy, who will head the new unit, said in a presentation at the commission’s open meeting.
Deputy Solicitor Robert Kennedy
Previously, requests for rehearing were assigned to lawyers who drafted the original orders and who also handle other matters, some with legal deadlines, Kennedy said. The new group, consisting of attorneys not involved in the original orders, will partner with subject matter experts while providing a “fresh set of eyes” on its decisions, Kennedy said.
“We anticipate that the primary role of the rehearing group will be to make sure that the commission has … fulfilled its legal obligation to articulate the connection between the facts found and the choice made, and to respond meaningfully to legitimate objections raised by the parties before it,” Kennedy said.
Kennedy said the new group doesn’t have any metrics regarding the backlog of rehearing requests and is still getting a sense of the workload and how much staffing will be needed. Chairman Norman Bay told reporters the group had just been staffed up the week prior.
“Ultimately… our metric will be how we do in the Court of Appeals,” Kennedy said.
Due Process
Bay, a former federal prosecutor, pointed to the appeals process in the courts as a model for the new process. “When there’s a petition for rehearing, virtually every single court in the country decides on a summary basis unless there’s some new claim that has been raised,” he told reporters. “And that certainly comports with due process. The commission, though, historically has not done this.”
Even if the arguments raised in a rehearing request are the same as in the original filing, FERC has written a “fulsome” order responding to those claims. “I don’t know how efficient that is from an administrative perspective,” he said.
Bay wants FERC to focus on anything different that’s been raised in a rehearing request. A claim can’t be entirely new, as new evidence or information cannot be introduced in a rehearing request. “But if there’s some variation of an argument that’s already been raised, that truly has not been considered by the commission, then we ought to be focusing on that, as opposed to reiterating what might have been said earlier,” Bay said.
The chairman said that the change was not prompted by any specific case or cases.
Complaints in federal court about the amount of time FERC takes in issuing orders on rehearing requests have never been successful, according to FERC.
“The commission always strives to examine what it’s doing and, when appropriate, looks to build upon what it’s doing and to improve what it’s doing,” Bay said. “And I think that this effort reflects this approach. We already do a good job, in my view, with respect to rehearings.”
“I certainly expect that parties before the commission will appreciate the effort to get rehearing orders out more quickly,” Commissioner Cheryl LaFleur said. “I’m certainly going to be paying particular attention to these orders especially in the first few months to ensure we properly balance clarity and efficiency.”
A New Look
Kennedy presented the first two rehearing orders under the new process: one denying rehearing of FERC’s decision to suspend for five months GenOn Energy Management’s proposed reactive power tariffs (ER15-2571, et al.) and another denying rehearing of its decision to prohibit Alliance Pipeline from removing authorized overrun service from its rate schedule (RP15-1022).
As promised, the orders are much more concise than the usual rehearing order, omitting lengthy sections that explain the full procedural history of the case, including all the protests and comments filed by intervening parties. The Alliance order is a mere one page, simply reading: “Alliance’s request raises no matter warranting any modification of [FERC’s original November 2015 order]. Nor does it warrant any further comment on rehearing. Accordingly, the request for rehearing is denied.”
The GenOn order, while longer, is still a brief six pages. “The format, rather than the substance, of the draft order is notable,” Kennedy told the commission.
FERC accepted GenOn’s revenue requirements for reactive power service from several of its power plants but suspended them until March 31. The company requested rehearing based on this provision, as well as the commission’s decision to refer the matter to its Office of Enforcement.
The order summarizes this background in two paragraphs before coming to the commission’s determination, which focuses exclusively on these two issues. The commission explained its methodology for setting the five-month suspension period, as well as citing the broad discretion afforded to it by the courts to determine these periods. It also said that it referred the request to Enforcement because it found the company may have continued to receive payments for reactive service from plants no longer capable of providing it.
The order concludes bluntly, “As to the request for clarification, we see no need to further clarify our underlying order beyond what we have stated herein.”
NEW YORK — The New York Public Service Commission Tuesday approved a contract to keep the struggling R.E. Ginna nuclear power plant operating through March 2017 (14-E-0270).
The commission approved a reliability support services agreement between distribution utility Rochester Gas & Electric and Exelon’s Constellation Energy Group, which had threatened to close Ginna because it was losing money.
The PSC ordered the RSSA in 2014 after determining that the 610-MW plant on Lake Ontario was needed to maintain reliability. The PSC’s action Tuesday approves an agreement filed in October by the companies. (See Ginna Lifeline to End in 2017; Profits After ‘Unlikely’.)
The contract, which was endorsed by large industrial customers, is subject to FERC approval.
RG&E will charge ratepayers $425 million to $510 million to cover Ginna’s full cost of service, with the final amount determined based on Ginna’s revenues from the NYISO wholesale market. The utility also will apply $110 million in customer credits to the contract, making the total price tag as high as $620 million.
Ratepayers began paying higher rates in September to mitigate the effects of rate compression.
“The joint proposal strikes a balance and protects consumers by making use of the customer credits and also protects the financial health of” RG&E, PSC Chairwoman Audrey Zibelman said.
Transmission upgrades expected to be completed next year will address the reliability concerns resulting from the plant’s closure.
However, Ginna’s life could be extended beyond March 2017 under a PSC proceeding to provide financial incentives to keep upstate nuclear plants operating until large-scale renewable energy facilities are deployed. The plan is part of Gov. Andrew Cuomo’s proposed Clean Energy Standard, which he wants finalized by June. (See New York Would Require Nuclear Power Mandate, Subsidy.)
Exelon has said the CES “could provide a meaningful path to sustain” Ginna and its Nine Mile Point nuclear plant.
Another upstate nuclear plant, the James A. FitzPatrick station, is expected to close by early 2017. Its owner, Entergy, says the subsidy plan has come too late to save it.
FERC last week rejected the city of Osceola’s demand that Entergy Arkansas provide refunds for unlawful bandwidth equalization payments it allegedly passed on to the city over three years. The commission said Osceola had already settled its claim with Entergy and is not entitled to another set of refunds (EL 16-7).
The northeastern Arkansas city took issue with Entergy’s 2007, 2008 and 2009 formula rate update proceedings. Osceola asked that Entergy refund $4.48 million plus interest for charges it said were improperly passed on to the city.
The city argued that Entergy violated the filed rate doctrine because the formula rate in Entergy’s service agreement precedes FERC’s 2015 Entergy bandwidth remedy, which was created to equalize production costs among Entergy’s several companies by making sure no Entergy arm has production costs 11% above or below the Entergy system average.
Osceola said the dispute was “substantially identical” to a dispute Entergy had with Union Electric, which obtained bandwidth payment refunds.
But FERC found that Osceola previously settled the claim in “black-box” settlements.
“We find that these pleadings, settlement agreements and commission orders fully dispose of the complaint. … We likewise decline to invade the formula rate update proceedings’ privileged settlement negotiations by discussing which party sought or provided what data or by inquiring what lies inside the black-box agreements,” FERC wrote.
Reversing a prior decision, FERC ruled Tuesday that PJM transmission owners should pay all of the cost of projects that solely address a TO’s local planning criteria (ER15-1387).
The commission accepted the proposal by PJM Transmission Owners, saying it had erred in its May 2015 order rejecting the Tariff change as contrary to Order 1000.
The commission also made its first application of the new rule, rejecting PJM’s proposed cost allocation for Dominion Resources’ Cunningham-Elmont rebuild project (b2582). The commission said that it was not eligible for regional cost allocation because it only addressed local needs (ER15-1344).
FERC based its original decision on a mistaken understanding that all projects in the RTO’s Regional Transmission Expansion Plan are included for the purpose of regional cost allocation.
Based in part on a Nov. 12 technical conference and comments submitted afterward, the commission acknowledged that the RTEP lists some local projects that are included solely to ensure consistency with PJM’s overall regional expansion plan.
“Based on the rehearing requests and comments on the technical conference, it has become clear … that it is just and reasonable for the costs of projects with these characteristics to be allocated entirely to the zone of the individual transmission owner whose Form 715 local planning criteria underlie each project,” FERC said.
The commission said the rehearing order was consistent with its earlier finding approving MISO cost allocation provisions for baseline reliability projects (ER13-187, et al.).
Cunningham-Elmont
In the second order, FERC accepted PJM’s proposed cost allocation for 60 low-voltage baseline reliability projects but told it to revise the cost assignments for the 500-kV Cunningham-Elmont project based on the revised cost allocation rule.
Dominion originally submitted the $106 million rebuild as a supplemental project, meaning it alone would pay for it, but later revised its end-of-life criteria. PJM reclassified it as regional baseline project, determining a reliability violation would occur if it were taken out of the RTEP.
Dayton Power & Light protested the change, accusing Dominion of exploiting what it called a loophole to shift costs from its ratepayers to the entire RTO. It said the project was a replacement for an existing line “for which Dominion has always had 100% cost responsibility” but later recharacterized it as a “new” line eligible for regional cost allocation. Double-circuit 345 kV and 500 kV and above projects are allocated 50% on a postage stamp basis and 50% based on a solution-based DFAX analysis.
Dayton also said that as a project eligible for regional cost allocation, Cunningham-Elmont should have been subject to a competitive proposal window under Order 1000. (See DP&L Protests Dominion Project Over New Cost Allocation.)
PJM designated the project as an immediate need, meaning it was not required to open the project to competition.
While the commission found that PJM had correctly designated the project, it scolded the RTO for not providing enough transparency into the designation process. In filings and at the technical conference, PJM officials acknowledged there was no language in its governing documents detailing how a project is reclassified from supplemental to baseline.
FERC said that the RTO should post information regarding immediate-need projects more explicitly on its website, rather than relying on presentation materials at its Transmission Expansion Advisory Committee meetings. “We expect PJM will improve its processes to post information,” FERC said.
LaFleur Dissents
Commissioner Cheryl LaFleur dissented in part on both orders, saying that high-voltage projects such as Cunningham-Elmont should be eligible for regional cost sharing even if they were developed for local needs.
“I would condition acceptance of the PJM transmission owners’ filing on the preservation of the current regional cost allocation method for certain high-voltage projects, even if those projects are selected solely to address local planning criteria,” she said.
FERC has previously found that high-voltage projects have significant benefits for the entire PJM footprint, she noted. “I continue to believe that these high-voltage projects in PJM, even if developed solely to address local planning criteria, provide regional benefits that warrant some regional cost allocation,” LaFleur said.
Undermining Order 1000
LaFleur seemed sympathetic to complaints by ITC Mid-Atlantic Development and LSP Transmission Holdings that the TOs’ proposal would undermine the competitive process set out in Order 1000.
The majority rejected the companies’ arguments, citing data from the TOs that for 98% of the 303 projects included in the RTEP solely to address local transmission owner planning criteria, costs have been allocated exclusively to the individual TO’s zone.
It also noted that where PJM finds that a project is needed not only for local planning criteria but also regional needs, “costs may be allocated outside of the zone of the transmission owner that filed the criteria” and a nonincumbent transmission developer could be selected to build it.
But LaFleur pointed out the TOs’ admission that “the overwhelming majority” of the 303 projects they cited were lower voltage facilities. “They therefore fail to demonstrate that this dataset is representative of high-voltage projects that the PJM Transmission Owners previously argued, and the commission previously found, confer regional benefits.”
“Order No. 1000 was intended to ensure just and reasonable transmission rates through the improvement and expansion of regional planning and the introduction of competition,” LaFleur wrote. “Even if crafted within the letter of Order No. 1000 and the commission’s compliance orders, proposals to limit access to existing regional cost allocation and competitive bidding processes are, in my view, inconsistent with the rule’s underlying goals.”
WASHINGTON — FERC won’t be revisiting the demand response compensation rules under Order 745, commissioners said Monday.
After the Supreme Court upheld Order 745 last month, Commissioner Tony Clark urged the commission to reconsider the order’s requirement that RTOs pay DR the same LMPs as generation, which he said “continues to be widely panned by market experts.” (See Clark Calls for New Look at Order 745.)
But at the National Association of Regulatory Utility Commissioners winter meetings, Chairman Norman Bay and the commission’s two other members, Cheryl LaFleur and Colette Honorable, said they had no intention of revisiting the issue.
“I think that the Supreme Court got it right,” Bay said in a brief interview after a question-and-answer session with NARUC President Travis Kavulla in front of hundreds of regulators and industry stakeholders.
Bay told Kavulla, “I don’t see [FERC undertaking] any major initiatives” as a result of the court’s ruling that the order did not intrude on state jurisdiction and that its compensation scheme was not arbitrary and capricious. “I think it’s really about implementing Order 745 at this point.”
Honorable said afterward that she agreed with Bay. “I believe the court spoke very clearly. … I don’t see a need to revisit compensation because the courts have upheld” FERC’s order, she said.
LaFleur, the only member of the current commission who cast a vote on the 2011 order, said she had no reason to second guess her position regarding compensation. “It’s just starting to be actually used now as the cloud [of litigation] is lifted,” she said.
The commission’s majority, led by former Chairman Jon Wellinghoff, said full LMP was appropriate because rates should reflect the service provided rather than the provider’s cost. The commission also said it would be difficult to establish “G” in the formula because retail rates vary within states and over time.
Former Commissioner Philip Moeller dissented on the order, saying DR should be paid a price of LMP minus G, where “G” stands for the retail price of electricity.
Moeller, now an executive with the Edison Electric Institute, reiterated his position last week at a briefing of financial analysts in New York, saying he hoped the commission would re-evaluate the rule “sooner rather than later.”
Under the commission’s current composition, however, DR providers such as EnerNOC, Centrica’s Direct Energy and Johnson Controls’ EnergyConnect have no reason to fear a pay cut.
Clark, who joined the commission after Order 745, won’t be around to fight for a change, having announced that he won’t seek reappointment when his term ends in June. (See Clark Won’t Seek New FERC Term.)
NEW YORK — Investor-owned utilities will have a central role in the expansion of distributed generation and renewables, ensuring profit growth even as load remains flat, the industry’s trade group told securities analysts Wednesday.
At its annual Wall Street briefing, leaders of the Edison Electric Institute touted utilities’ dividend growth and partnerships with technology companies to make their case for utility stocks.
But when EEI President Tom Kuhn and five other executives completed their presentations and opened the floor to questions, the first query addressed the lack of load growth, an analyst calling it “the elephant that, frankly, is not in the room.”
“You have had no sales growth whatsoever in something like the past eight years despite the increase in the economy. My question to you is: What are you going to be selling … to customers in the future if they’re not buying electricity?”
Tom Kuhn
Kuhn said that while increasing efficiency has disconnected load growth from the gross domestic product, it is also providing opportunities for capital expenditures — about $7 billion annually, he told about 150 analysts at the luncheon session at the University Club off Fifth Avenue in Manhattan.
He also cited spending on grid security and opportunities in the electrification of transportation.
“You want to sell what’s best for the customer,” Kuhn said. “In the future it may be things that flatten load — storage and other kinds of things … I think [vehicle] electrification is an important part of the equation, but [we’re] not really counting on major electricity growth to deliver what’s best for the customer.
“Over the past seven years, although load hasn’t really increased, you’ve seen utilities do pretty well,” he continued, citing the growth in dividends (39 of 46 publicly traded companies tracked by EEI raised dividends in 2015) and stock prices (up 71.5% over five years, despite a 3.9% drop in 2015).
Kuhn blamed 2015’s drop on rising interest rates and low natural gas prices. The EEI index’s 2015 performance trailed the Dow Jones Industrial Average (0.2%), the S&P 500 (1.4%) and the NASDAQ (5.7%). EEI’s five-year average beat the Dow Jones (70.8%) but fell short of the S&P (80.8%) and NASDAQ (88.8%).
The EEI index was up 7% in January, however, while broader indexes lost more than 10% amid concern over slowing economic growth in China.
Kuhn noted that utility credit ratings have improved to an average of BBB+, with 84% of companies rated as stable or positive as balance sheets have shifted toward regulated operations and away from competitive businesses.
Capital expenditures, which hit a record $108.6 billion in 2015, are forecast at $101.2 billion for 2016 and $92.2 billion next year. Spending, which was formerly dominated by generation, has shifted to distribution, which has doubled its share over the last five years, he said.
‘Enhanced Relationship’
In recent strategy meetings with utility CEOs, EEI identified grid modernization, clean energy and customer solutions as areas for growth, said David Owens, executive vice president for business operations and regulatory affairs.
David Owens
“It’s not just about electricity sales. It’s about your enhanced relationship with the customer,” Owens said.
It is utilities that are developing microgrids for military bases and that will build the charging infrastructure needed for electric vehicles, he said.
“We have many customers who are looking at a full array of technologies where they have greater control over their usage and greater control over their bills,” he said. “We’re seeking to become a full-service provider behind the meter… so we see a bright future.”
Role in Renewables
Richard McMahon, vice president of energy supply and finance, said utilities are the “primary investors” in all forms of renewables, with utility-scale solar representing 60% of all installed solar capacity.
EEI’s solar value proposition is cost. Utility-scale solar costs less than half as much as roof-top panels ($1.48/W versus $3.55/W for the first three quarters of 2015), according to the group.
McMahon said utilities also will be “major players” in buying and deploying storage. “Maybe the one silver bullet in energy storage hasn’t emerged yet, but there’s a lot of testing … currently going on in the industry and its happening really across the value chain,” he said, citing uses at the wholesale level for peaking, at transmission for voltage control and in distribution for power quality.
Brian Wolff, executive vice president for public policy and external affairs, touted EEI’s 182 technology partnerships with the likes of Tesla, Apple, Google and Nest Labs. “We view many of the so-called ‘competitors’ or ‘disruptors’ to our industry as partners,” he said.
EEI members spent more than $90 million last year to add 800 plug-in electric vehicles to their fleets. Seventy utilities have committed to invest at least $250 million over the next five years to increase their EV fleets. “This helps to push down vehicle development costs for automakers, making EVs more affordable for customers,” Wolff said.
Policy Initiatives
In addition to making their case for utility stocks in investors’ portfolios, EEI officials also briefed analysts on the group’s policy initiatives — chief among them changing state net metering policies to eliminate cost shifting from customers with rooftop solar. Owens said legislatures or utility regulators in more than three dozen states are considering changes.
The issue could be addressed by increasing charges for the fixed costs of the grid; through separate rates for buying and selling power; or a three-part rate, including a monthly basic service charge, a demand charge and an energy charge, Owens said.
Wolff expressed disappointment that a bipartisan energy bill stalled in the Senate earlier this month over aid to Flint, Mich., which is seeking funding to address lead in its water system. Assuming the hurdle is overcome, it would have to be reconciled with legislation that cleared the House earlier.
Although Senate leaders said they will reconsider their bill later this year, Wolff said, chances of passage are far from certain. “The closer we get to the election, the less appetite Congress has for doing big things,” he said.
Former FERC Commissioner Philip Moeller, who joined EEI last month as senior vice president of energy delivery and “chief solutions officer,” expressed disappointment at the Supreme Court’s January ruling upholding FERC Order 745.
Moeller was the lone dissenter on the order, which required RTOs to pay demand response at the same LMP rate as generation. Moeller argued for payment of LMP minus the avoided cost of generation. “I hope the commission will [revisit DR pricing] sooner rather than later,” he said. (See Clark Calls for New Look at Order 745.)
Ohio PPAs
EEI executives declined to take sides when asked about the power purchase agreements FirstEnergy and American Electric Power are seeking for their merchant generation in Ohio. The issue has pitted EEI Chairman Nick Akins, AEP’s CEO, against EEI Vice Chairman Chris Crane, CEO of Exelon. (See Exelon Calls FirstEnergy PPA ‘Grossly Lopsided,’ Says it Can Offer a Better Deal.)
All but one of the Ohio plants at issue are coal-fired, the exception being FirstEnergy’s Davis-Besse nuclear station.
But EEI’s McMahon chose to focus on the woes of nuclear plants whose revenues have decreased as low natural gas prices have lowered clearing prices — an issue on which AEP, FirstEnergy and Exelon are in agreement.
“I think there’s an overall recognition that companies are going to do what they need to do” to protect their baseload generation, he said. “Our focus has been more working with the FERC, working with the other trades and the RTOs to address these issues so that the markets really provide the appropriate price signals to those companies.”
FERC’s general counsel told a congressional subcommittee that there are “significant benefits” to a proposed amendment to the Federal Power Act that would allow challenges to rates that take effect as a result of a commission deadlock.
The proposed amendment to Section 205 was considered in a hearing before the House Energy and Power Subcommittee on Feb. 2.
Kennedy III
The Fair RATES Act (H.R. 2984) was proposed last year by Rep. Joseph P. Kennedy III (D-Mass.) after he found there was no legal recourse to challenge the results of ISO-NE’s eighth Forward Capacity Auction. The results were certified “by operation of law” in 2014 when commissioners failed to take action and indicated in public statements that they were split 2-2. (See FERC Commissioners at Odds over ISO-NE Capacity Auction.)
FCA 8, effective for the 2017/18 capacity commitment period, saw capacity costs total $3 billion, about triple the previous year’s results. New England’s congressional delegation protested the results but found itself in legal limbo because there was no FERC order on which to request a rehearing by the commission, nor any way to appeal to federal court.
“Appellate review is an important procedural avenue for those who do not prevail before an administrative agency. It would also correct an unusual outcome in a specific context that may arise when the commission has four voting members,” FERC General Counsel Max Minzner said.
FERC’s five-member panel dropped to four again last fall with the departure of Commissioner Philip Moeller. Thus the commission could find itself split again when it is asked to certify the results of FCA 10, which was held Monday. (See Prices Down 26% in ISO-NE Capacity Auction.)
“This outcome is certainly not impossible before we get this law across the finish line … given the fact that there are four [commissioners] … and no other nominations are in the pipeline,” Kennedy said.
Minzner said a complainant persuasive enough to convince a second commissioner of the merits of its case deserved an opportunity for further review.
He said he is aware of only six times under the FPA or the Natural Gas Act when a public utility filing went into effect without a FERC order. However, Minzner said he believes any change in the law should apply to “future cases,” leaving FCA 8 results intact.
After the congressional hearing, Sen. Edward Markey (D-Mass.) introduced a version of Kennedy’s bill in the upper chamber (S. 2494). The two congressmen also wrote a letter to President Obama urging a nomination to fill the current vacancy and pointing out that the five-member panel could be reduced to three with Commissioner Tony Clark not seeking reappointment when his term ends in June. (See Clark Won’t Seek New FERC Term.)
“The returns over the last two years are inconsistent with our commitment to investors to provide predictable, stable earnings and cash flows. We believe there will be demand for this international portfolio at a reasonable valuation. The proceeds will be used to strengthen our balance sheet and help fund growth in our core businesses,” CEO Lynn Good said on a call with analysts.
