Six environmental groups called Wednesday for the immediate closure of the Indian Point nuclear plant.
The Sierra Club, Riverkeeper, Hudson River Sloop Clearwater, the Indian Point Safe Energy Coalition, Scenic Hudson and Physicians for Social Responsibility asked the Nuclear Regulatory Commission to suspend plant operations until Indian Point’s safety is reviewed by state and federal investigators.
Indian Point Nuclear Plant
The plant is under investigation following a series of mishaps in recent months, including radioactive water leaks and two unplanned outages. NRC is investigating the leakage of radioactive water into test wells. The New York departments of Health and Environmental Conservation are conducting their own investigation along with the Public Service Commission. (See NRC: No Further Leakage at Indian Point.)
“Currently Entergy is unable to properly access its aging labyrinth of more than 3 miles of pipes beneath the Indian Point site,” said Sierra Club President Aaron Mair. “Entergy focuses on tritium, but the actual leak likely contains a collection of radioactive elements, including Strontium-90, Cesium-137, Cobalt-60 and Nickel-63, that could migrate off the property.”
Federal officials and plant owner Entergy say the incidents have not endangered the public.
Entergy dismissed the most recent criticism. “Some organizations who are longtime opponents of nuclear power will take opportunities to try and frighten the public. The fact is this issue cannot have any impact on public health or safety,” spokesman Jerry Nappi told RTO Insider Friday.
U.S. Sen. Charles Schumer said he understands critics’ frustration and said he was among the plant’s harshest critics. But he also told the Mid-Hudson News Network that the plant’s continued operation is vital to keeping electricity affordable.
“I have told some of the environmental people, if you can show me a plan to figure out a way to replace that electricity, fine, but if you can’t, it’s going to raise electricity rates 30% or 40%, [rates] which are high enough on average people and that’s not the way to go. In the meantime, I have emphasized very strong safety,” Schumer said.
Gov. Andrew Cuomo has advocated the plant’s closure due to its proximity to New York City.
“The NRC shouldn’t ask the public to take its chances when so many questions are unanswered and the stakes are so high,” said Riverkeeper President Paul Gallay. “Since May 2015, Indian Point has suffered seven major malfunctions, from pump failures to transformer explosions, to radiation leaks, power failures, fires and oil spills. … Pending completion of the state and federal investigations, we must close Indian Point. These mishaps are happening on an accelerated pace. We shouldn’t be asked to wait for the next one.”
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.
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.
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.
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.
