Page 1674 – RTO Insider

February 25, 2016

Zibelman: Guaranteed-Savings Rules Meant to Enable Markets

By William Opalka

New York Public Service Commission Chairwoman Audrey Zibelman said that consumer protections approved by regulators Tuesday are meant to combat deceptive practices and boost consumer confidence at a time when more complex energy products are entering the market.

“We found that consumers were paying higher prices by buying from a retailer than they would if they were buying from a utility,” she said in a conference call with media Wednesday.

The PSC held the unusual conference call a day after it approved new rules that drew fire from a national trade group for electric supply retailers. The regulations guarantee savings for retail and small commercial customers who switch to an alternative electric supplier. The rules also provide for tougher enforcement measures against those who prey on vulnerable or uniformed customers (15-M-0127, et al.).

In response, the Retail Energy Supply Association said the rules will only drive energy supply companies out of New York.

Retail Choice ‘Eliminated’?

“The New York State Public Service Commission took the unprecedented action of effectively eliminating retail choice for residential and small commercial customers in New York by substituting the commission’s judgment for that of consumers in determining what energy products offer value,” the group said in a statement.

“Under the commission’s order, retail suppliers would be forced to guarantee savings against a future utility price that, as a monthly variable price, is unknown,” RESA added.

Zibelman said the rules, which are meant to prevent overcharging, are part of the PSC’s plan to provide clear rules for companies and consumers under the Reforming the Energy Vision initiative.

“As we move forward with REV, it’s very important to us that the residential and mass market[s] are able to participate and acquire additional energy services … and in order to do that, we need a great deal of market confidence,” she said.

The commission said “retail energy markets are not providing sufficient competition or innovation to properly serve mass market consumers,” in contrast with markets for large commercial and industrial customers, which it said “are providing substantial benefits … including a wide range of energy-related value-added services that assist customers in managing their energy usage and bills.”

A year-long proceeding under the REV is determining what constitutes a value-added service and how it should be priced, Zibelman said.

The guaranteed-savings rule does not apply to customers opting to buy “green” power. Energy service companies (ESCOs) that offer premium-priced renewable energy will be required to obtain at least 30% from sources eligible under the commission’s Environmental Disclosure Labeling Program, including biomass, biogas, hydropower, solar and wind.

Abuses Cited

The commission is conducting an audit of the 200 ESCOs that operate in New York.

“We have zero tolerance for these unscrupulous companies, whose business model is to prey on ratepayers with promises of lower energy costs only to deliver skyrocketing bills,” Gov. Andrew Cuomo said in a statement. “These actions will root out these bad actors and protect New Yorkers from these unfair and dishonest tactics.”

The commission may impose a “one strike and you’re out” rule for behavior it decides is egregious. It also created a “do not knock” rule for door-to-door solicitations, similar to a “do not call” registry for telemarketers. Violators could be prohibited from operating in the state.

More than 20% of New York’s residential and small commercial customers currently receive energy from ESCOs. There are about 7 million residential electric customers and roughly 4.3 million residential natural gas customers, according to the PSC.

The regulators cited several examples of unacceptable conduct, including four companies in the Hudson Valley that charged more than double Central Hudson Gas & Electric’s price for electricity; a New York City company that charged more than triple Consolidated Edison’s rate for electricity; several ESCOs in upstate New York that charged more than double National Grid’s electric rate; and a company in the Finger Lakes region whose variable rate plan for electricity was eight times what Rochester Gas & Electric charged.

The commission also cited examples of companies falsely representing themselves as local utilities to trick customers into signing inflated contracts. At the Tuesday meeting, commissioners were particularly disturbed by reports of deceptive practices used against customers for whom English is a second language.

February 25, 2016

New Lifeline for FitzPatrick Nuclear Plant

By William Opalka

NEW YORK — In a last-ditch effort the save the James A. FitzPatrick nuclear plant, New York regulators are proposing financial incentives that could be available to the plant’s owners by July.

The New York Public Service Commission on Tuesday proposed to expedite subsidies to keep the plant operating while a more permanent incentive is crafted on the normal regulatory schedule (15-E-0302). A public comment period will last until May 2.

However, Entergy, FitzPatrick’s owner, again said the state’s plans were too uncertain and too late to save the plant on Lake Ontario. Entergy intends to close the plant on Jan. 27, 2017, when its current fueling cycle ends.

New York’s attempts to prop up its nuclear fleet exclude Entergy’s Indian Point nuclear plant, which Gov. Andrew Cuomo wants to close because of its proximity to New York City.

“If the state is focused on reducing CO₂ emissions, the Clean Energy Standard should apply to Indian Point, which is an essential generation resource critical to the state’s goal of reducing CO₂ emissions,” spokeswoman Tammy Holden told Syracuse.com.

Entergy Vice President of External Affairs Mike Twomey said in a statement that no definitive proposal from New York for FitzPatrick has been received since negotiations broke down last year.

“While we share the NYPSC’s concerns about the loss of nuclear generation, the financial implications of its efforts are too uncertain and this proposal comes too late to save FitzPatrick,” he said.

“Entergy met with New York state officials from the governor’s office and with the PSC repeatedly over the last few years to discuss how the current New York market structure disadvantages nuclear generation, how nuclear power’s carbon-free attributes could be recognized in the market and the financial challenges faced by the FitzPatrick plant. Unfortunately, these discussions resulted in no meaningful progress or policy changes by New York state.”

The PSC is already working to create a new tier of zero-emission credits (ZECs) that would be available to upstate nuclear generators next year. The proposed Clean Energy Standard is meant to help put New York on a path to 50% renewable generation by 2030. Nuclear is seen as a zero-carbon bridge to that plan. (See New York Would Require Nuclear Power Mandate, Subsidy.)

The process gained urgency after NYISO released an assessment finding that New York will be short of generation in 2019 with the closing of FitzPatrick and other plants. (See Fitzpatrick Closure Could Leave NY Generation Short.)

The PSC’s move to expedite subsidies to FitzPatrick “gives the commission the opportunity to act very decisively,” Chairwoman Audrey Zibelman said Tuesday. “We do not want to see a plant retire from [the lack] of a short-term solution.”

The expedited subsidy schedule would enable Entergy to refuel FitzPatrick if the company were to change its mind and continue operating the plant.

The PSC plan is modeled after existing renewable energy procurement practices used by the New York State Energy Research and Development Authority. NYSERDA purchases credits using money made available to it by the commission, including system benefits charges. The ZEC funds would also include other money collected from ratepayers.

As in renewable energy production, each ZEC would be paid for 1 MWh of energy produced. ZEC payments would be no more than the amount necessary above existing revenue streams to cover the ongoing costs of the facility for operations and maintenance, capital expenditures, taxes and other expenses. Sunk costs would be excluded.

Raj Addepalli, the PSC’s managing director of utility rates and service, offered a rough estimate of $15/MWh, using as a benchmark the “very complicated” formula just approved by the commission to keep the R.E. Ginna nuclear plant operating. (See NYPSC OKs Ginna Deal.)

That figure was derived from the payments to Ginna under its reliability support services agreement that will fluctuate from $49 to $52/MWh, minus the recent yearly average wholesale energy price of $35/MWh.

Ginna would be eligible to participate in any ZEC program after its RSSA expires on March 31, 2017.

February 25, 2016

Cayuga Coal Plant in Jeopardy

By William Opalka

NEW YORK — The future of one of New York’s last coal-fired generators is in jeopardy following state regulators’ rejection of a plan to repower it to natural gas and their approval of a transmission alternative (12-E-0577), (13-T-0235).

The 312-MW Cayuga generating plant will soon be one of two remaining coal generators in the state, plants that Gov. Andrew Cuomo recently vowed to close or have converted to natural gas by 2020.

But a ratepayer-funded repowering is off the table, the New York Public Service Commission ruled Tuesday. Chairwoman Audrey Zibelman said it would be “unfair” for ratepayers to be saddled with $102 million in additional costs to pay for the repowering. “It would not be in the public interest for New York State Electric and Gas ratepayers to be paying for that,” she said at the meeting. (See Cayuga Power Plant Repowering Opposed.)

She later told RTO Insider that plant owners “are free to repower the plant on their own nickel.”

In a separate order, the PSC signed off on Upstate New York Power Producers’ (UNYPP) sale of Cayuga and the Somerset coal plant outside Buffalo to Riesling Power, a unit of the Blackstone Group (15-E-0580). FERC approved the transaction in January. (See FERC Approves Sale of Doomed New York Coal Plants.)

Over UNYPP’s opposition, the commission also approved a request by distribution utilities NYSEG and Niagara Mohawk to build a two-phase, 14.5-mile project connecting two substations to address reliability concerns in western New York. The $23.3 million Auburn project would use existing rights of ways in Cayuga and Onondaga counties.

Phase 1 was filed as a proposal to build the 115-kV project, with Phase 2 proposed as a supplemental project by the companies to increase its capacity.

A recommended decision in November by an administrative law judge said, “it is uncontroverted that Phase 1 of the project should be constructed as soon as possible to remedy an immediate need to avoid reliability violations and service disruptions, if a major contingent event occurs.”

UNYPP objected to Phase 2, saying that part of the project is not needed if the plant continues to operate. According to the judge’s record decision, both phases are necessary even if the Cayuga units continue to sell into the NYISO market.

The plant is operating under a reliability support services agreement with NYSEG that runs through June 2017 (12-E-0400).

February 24, 2016

Supreme Court Offers Little Support to CPV, Md.

By Rich Heidorn Jr. and Michael Brooks

WASHINGTON — Lawyers for Maryland and Competitive Power Ventures got little support from Supreme Court justices during oral arguments in their federal-state jurisdiction case Wednesday.

The justices also interrogated Paul Clement, attorney for Talen Energy Marketing, which challenged Maryland’s deal for CPV’s combined cycle plant now under construction in Charles County as an improper subsidy.

But none gave any indication that they were inclined to reverse in their entirety lower court rulings voiding the contract. Rather, several justices seemed to be wrestling with whether to reject the contract based on “field preemption” — that it was an intrusion into exclusive federal jurisdiction — or a narrower “conflict” ruling — that it undermined FERC policy because its long-term pricing structure includes incentives different from those provided by PJM’s capacity auction. (Hughes v. Talen Energy Marketing (14-614), CPV Maryland v. Talen Energy Marketing (14-623))

In April 2012, the Maryland Public Service Commission ordered Baltimore Gas and Electric, Potomac Electric Power Co. (PEPCO) and Delmarva Power and Light to enter into a contract that guaranteed CPV — winner of a PSC competitive solicitation — an income stream so that it could finance the facility.

Under the “contract for differences,” CPV St. Charles’ revenues for the sale of 661 MW of energy and capacity would be compared to what the company would have received had the contract prices been controlling. If the contract prices were higher than the market prices, the three electric distribution companies would pay the difference to CPV; if market prices were higher than the contract, CPV would make payments to the EDCs.

The contract was challenged by Talen Energy’s predecessor, PPL, and other generators.

The U.S. District Court of Maryland ruled with PPL and other plaintiffs in saying the contract violated FERC jurisdiction over the wholesale electric market, a ruling upheld by the 4th Circuit Court of Appeals. The Supreme Court declined to hear two related cases in New Jersey decided by the 3rd Circuit.

Opponents said Maryland’s action would suppress capacity prices and that allowing the contract to stand would mean that eventually only subsidized units would enter the auction because those without support could not compete.

Chief Justice John Roberts picked up on this argument shortly after Maryland attorney Scott H. Strauss began speaking. “If it doesn’t suppress prices, why did Maryland do it?” he asked bluntly.

Strauss responded that the state saw a need for more generation than the PJM capacity market was providing. He and CPV attorney Clifton S. Elgarten argued that FERC had addressed price-suppression concerns with the minimum offer price rule (MOPR), which sets a floor on bids by new entrants.

Clement said FERC was siding with Talen in the dispute because “MOPR is not some kind of cure-all that is designed to ward off any price-suppressive bid. … It is a coarse screen to deal with the most egregious cost-reducing bids. It also depends on an estimate of cost.

“And here’s why it doesn’t really work for a bid like this,” Clement continued. “One of the most important costs is your cost of capital. Because [CPV is] getting a 20-year guarantee and no one else is … it destroys the ability to do an apples-to-apples comparison. And then the one thing we know for certain here is that this project ended up displacing a project that actually could be built based on the three-year forward price and without a 20-year contract.”

Strauss insisted Maryland ratepayers would not be providing a subsidy. “Maryland concluded that this was going to be a better deal for ratepayers,” he said. At a time when the generation mix is changing, he said, “the last thing the court should do is to limit state options.”

Boston Pacific, a consultant hired by the PSC, estimated the contract would save residential ratepayers $0.32 to $0.49 per month over the life of the 20-year contract. However, PSC General Counsel Robert Erwin told a FERC technical conference later: “No one knows whether at the end of 20 years Maryland ratepayers will pay CPV or if CPV will have paid Maryland ratepayers.”

FERC’s Position

After the 4th Circuit upheld the lower court’s ruling, CPV filed the contract with FERC, asking the commission to find it just and reasonable. The company had hoped this would nullify the courts’ findings, but FERC said it wouldn’t review a contract that had been ruled invalid.

Strauss and Elgarten, however, maintained that the commission would have found it just and reasonable.

“I don’t understand your position,” Justice Samuel Alito told Elgarten sharply. “You’re arguing that FERC does not think this adversely affects the [capacity] auction? Why has FERC filed a brief arguing the opposite? You’re arguing as if they’re not even here.”

Alito was referring to Ann O’Connell, an assistant to the Solicitor General who argued for FERC. O’Connell made clear the commission’s position in her opening argument.

“In the government’s view, the Maryland generator order is preempted because by requiring the state-selected generator to bid into and clear the PJM capacity auction in order to receive the guaranteed payments provided in the contract, the Maryland program directly intrudes on the federal auction, and it also interferes with the free-market mechanism that FERC has approved for setting capacity prices in that auction,” she said.

“I understood why they were making the MOPR argument at the early stages of this litigation before FERC filed the brief,” Clement said. “But I am a little mystified why, at this late stage of the game, after FERC filed three briefs saying that the MOPR is not sufficient to eliminate price-suppressive bids, that they’re still saying ‘We win because FERC’s on our side.’”

Skeptical Justices

The justices questioned whether the contract would have been legal had it not been tied to the auction and simply subsidized by Maryland.

“It does seem to me important what the kind of state action is,” Justice Elena Kagan told Clement. “If the state had just said ‘we need another power plant’ and had delivered a load of money to CPV and said ‘go build a power plant,’ you’re not saying that that would be preempted, are you?”

“It would depend,” Clement responded. “The way you just described it, [it is] not preempted.”

Roberts posed the same question to O’Connell.

“If the state just paid to build a power plant, that’s not directly targeting what’s happening in the PJM auction,” she said. “Sure, it’s adding supply to the market. But as long as the state is staying within its sphere under the Federal Power Act, that’s fine.”

Some of the justices confessed that they were confused by the details of the PJM capacity auction, something that Elgarten pointed out in his arguments.

“All of the conflict preemption issues should be addressed to FERC,” Elgarten said. “They are not really for this court — which is obviously having trouble conceptualizing how this all works — to resolve.”

This remark did not seem to faze the justices, however. “Truer words were never spoken than ‘I am not quite on top of how this thing works,’” Justice Stephen Breyer said later.

“I’m a little bit like Justice Breyer on this,” Justice Sonia Sotomayor said. “I’m not quite sure how everything is working.”

February 23, 2016

Con Ed Reports Higher Earnings

By William Opalka

Consolidated Edison on Thursday reported 2015 net income of $1.19 billion ($4.07/share) compared with $1.09 billion ($3.73/share) in 2014.

Excluding the impairment of certain assets held for sale, the gain on sales of solar electric production projects, the impact of lease in/lease out transactions and the net mark-to-market effects of the competitive energy businesses, the company earned $1.2 billion ($4.08/share) in 2015, compared with $1.14 billion ($3.89/share) the year before.

For the fourth quarter of 2015, unadjusted net income totaled $176 million ($0.60/share) compared with $81 million ($0.28/share) in the fourth quarter of 2014. Adjusted, earnings were $178 million ($0.61/share) in 2015 compared with $171 million ($0.58/share) in fourth quarter 2014.

The company expects adjusted earnings of $3.85 to $4.05/share for 2016. The forecast reflects capital investments of $4.15 billion, which includes $985 million for the competitive energy businesses’ renewable and energy infrastructure projects.

“We embrace new technologies that are changing the energy industry and use them to partner with our customers,” CEO John McAvoy said in a statement. “Customers want more options, including the ability to generate power in their own homes or businesses and greater access to cleaner energy. We see potential throughout our businesses, and are confident that our experience and expertise make us a leader in our field.”

Con Ed said it will meet its 2016 capital requirements from cash flow and by issuing $1 billion to $1.5 billion in long-term debt at its utility subsidiaries. Additional debt will be secured by its renewable electric production projects. Con Ed also plans to issue up to $200 million in new common equity, in addition to equity created through its dividend reinvestment, employee stock purchase and long-term incentive plans.

February 23, 2016

MISO/PJM Joint and Common Market Meeting Briefs

MISO and PJM said last week they’re ready for the March 1 transfer of 300 MW of MISO pseudo-tied resources to PJM, and a 2,000-MW transfer set for June 1. The transitions will result in the creation of 80 new flowgates.

The 2,300 MW PJM and MISO will pseudo-tie over the 2016/17 planning year is a big jump from the 156 MW in pseudo-tied resources added in 2015/16.

MISO has said it wants to address price convergence and congestion management issues resulting from pseudo-ties before the June 1 transfer. MISO staff say there is little language on pseudo-ties in their Tariff.

During a Joint and Common Market meeting on Thursday, MISO proposed requiring the host RTO to provide capacity, schedule the firm exports, abide by a day-ahead must-offer requirement and provide resource status information. It also said that both RTOs should have a say in approving planned outages.

While PJM did not provide its own proposal, multiple PJM stakeholders criticized MISO’s plan, saying it was too similar to one proposed by MISO in 2012 and later scrapped. When some stakeholders suggested that the RTOs back a policy fix rather than an operational fix on capacity flows, Stu Bresler, PJM’s vice president of market operations, said a policy solution may exist, but it’s “much, much bigger than this group.”

“Our main concern was to ensure reliability. And to do that, we needed two things in place: good modeling … and an operating agreement,” Andy Witmeier, MISO’s senior manager of reliability coordination, said at a Feb. 10 Reliability Subcommittee meeting.

Witmeier said some details will not be resolved in time for the March and June implementation. “We are continuing to develop a compensation mechanism for use when unit commitment is needed for local congestion and cannot use [market-to-market],” he said. In the meantime, Witmeier said, “Safe Op Mode” will be used to compensate such units.

MISO Senior Director of Regional Operations David Zwergel said other commercial issues could arise as a result of the additional resources. MISO officials have said they do not expect full implementation of new pseudo-tie market rules before the 2017/18 planning year.

Regions Begin FFE Exchanges

PJM’s Tim Horger said the first day-ahead exchange of firm flow entitlements took place on Jan. 28, with the transfer of about 40 MW from MISO to PJM. About seven exchanges have occurred since, he said. A firm flow entitlement is the amount of firm flow on a flowgate an entity is entitled to use based on historical usage.

“I don’t think it was substantial as far as dollars are concerned, but it was the first one,” Horger said. “We think this is going to be very beneficial. We’re going to keep doing exchanges as long as it’s efficient for the markets. I think it’s good news here.”

Horger said the RTOs will monitor FFE exchanges and report on their progress during upcoming JCM meetings.

No Consensus on Interface Pricing

MISO and PJM said they have not reached a compromise on their interface pricing rules, so current rules will remain in place for at least a year.

Discrepancies in the RTOs’ interface pricing methodologies can result in double counting congestion, causing a revenue imbalance and uplift. The RTOs said the issue would be put on hold until mid-2017 while MISO conducts an analysis that uses data from December.

Jason Barker of Exelon said traders won’t use coordinated transaction scheduling without common interface pricing in place first.

MISO had proposed a solution using a “centroid-to-centroid” approach, with the non-monitoring RTO excluding a transaction’s impact on the constraint while PJM preserved its 10-bus common interface definition. (See “MISO-PJM Interface Pricing Project Heads to Final Four,” MISO Market Subcommittee Briefs.)

PJM, however, said that approach would have an “adverse impact on PJM market-to-market constraints” because the approach only accounts for half of the misplaced incentive for transactions and fails to eliminate the pricing overlap that exists in the RTOs’ current interface.

JOA Work not Done

FERC approved the RTOs’ revised joint operating agreement just last month, but officials concede there’s more work to be done on the pact (ER15-2613, et al.).

“If you look at the language in the JOA today, it’s cumbersome. We don’t think it makes a lot of sense for these quick-hit, targeted studies. … Some have said that there’s too many hurdles to interregional projects,” said Paul McGlynn, PJM’s senior director of system planning.

MISO is considering revising the JOA to give consideration to projects with lower voltage than the current 345-kV limit. McGlynn said he’d be interested in eliminating “undue thresholds” from the cross-border project approval process. Currently, interregional projects between MISO and PJM require both regional and interregional approval, and the RTOs use different evaluation metrics.

The new JOA includes rules for coordinating outages of pseudo-tied units and stipulates that a market-to-market approach should be followed when dispatching pseudo-tied generation for capacity and congestion.

It also establishes communication protocols between host balancing authorities (the physical location of the pseudo-tied generator), attaining balancing authorities (the region importing the generator’s output), transmission operators and market participants.

In approving the agreement, FERC praised the addition of FFEs, noting they “increase efficiencies in the day-ahead market, better align the operations of the day-ahead and real-time markets, and enhance revenue adequacy for other markets, such as financial transmission rights.” It was a marked change in tone from a year ago, when FERC expressed exasperation over PJM and MISO’s boundary disputes. (See Impatient FERC Hints at Action on PJM-MISO Seams Disputes.)

On Feb. 5, FERC also approved the RTOs’ request to remove their $20 million threshold on interregional market efficiency projects (ER16-488 and ER16-490).

The RTOs are soliciting stakeholder feedback for an annual issues review in April.

— Amanda Durish Cook

February 23, 2016February 27, 2025

ISO-NE Planning Advisory Committee Briefs

MILFORD, Mass. — Stakeholders have until April 1 to submit written requests for economic studies to be done in 2016 on generation additions or transmission upgrades that can relieve congestion and reduce LMPs.

ISO-NE will develop a scope of work and cost estimate for all requested studies and may add its own proposals. The RTO also will develop a preliminary prioritization based on expected benefits.

Presentations on proposals will be made at the April 20 PAC meeting.

“We need to have some specificity — the locations, the what, where and when,” said Michael Henderson, ISO-NE director, regional planning and coordination.

The PAC is scheduled to select up to three studies to be conducted, and determine the final order of priority, by June 1.

Last year, the RTO considered wind expansion scenarios in the Keene Road area of Maine, Northern New England and offshore Rhode Island and Massachusetts. (See “Draft Study Shows Greater Wind Penetration Benefits,” ISO-NE Planning Advisory Committee Briefs.)

ICR Forecast Shows Slowing Rate of Increase

ISO-NE is reducing its installed capacity requirement for commitment periods four to nine years into the future by an average of 500 MW compared with last year’s forecast, due to slowing load growth and the increase of behind-the-meter solar generation.

The calculations are based on the RTO’s 10-year forecast for capacity, energy, load and transmission, otherwise known as the CELT forecast. The models were adjusted to account for the announced closure of the Pilgrim nuclear power plant, slated for no later than mid-2019.

The RTO cited behind-the-meter solar in reducing its load forecast by 390 MW for the recently concluded 10th Forward Capacity Auction for the 2019/20 capacity commitment period. (See FERC Accepts ISO-NE’s Solar Count over Protests.)

The new ICR study period includes the years for FCA 11-15.

— William Opalka

February 23, 2016

Duke to Sell International Business

By Suzanne Herel

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.

February 23, 2016

Exelon Appeals ISO-NE Zero-Price Offer Requirement

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.

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.)

— William Opalka

February 23, 2016February 27, 2025

CO2 Emissions Increase in ISO-NE

By William Opalka

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.

“Emissions rose slightly, probably because of the closing of Vermont Yankee” at the end of 2014, Silva said. (See Vermont Yankee Retirement Leaves ISO-NE More Dependent on Gas.)

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.

The regulation has a seven-year phase-in period.