SACRAMENTO, Calif. — Energy issues appeared to get the back burner on the opening day of the California State Legislature as allegations of sexual harassment and workplace retaliation dominated the beginning of the 2018 session.
State Senate President Pro Tempore Kevin de Leon (D) spent most of Wednesday’s session meeting with fellow Democrats about allegations against Sen. Tony Mendoza (D), who agreed to temporarily step down. An aide to Mendoza filed a complaint with the state saying that she was fired after telling Senate officials he sexually harassed another female subordinate, a claim that Mendoza denies, TheSacramento Bee reported this week.
Since the 2017 session, the State Capitol has become a point of focus in a national debate on sexual harassment after nearly 150 women signed a letter complaining of inappropriate behavior in an elected body dominated by Democrats and known for progressive policies. De Leon, a former roommate of Mendoza, is tackling the controversy as he launches a campaign for the U.S. Senate seat held by Dianne Feinstein, another possible distraction from the energy policies he has championed. Senate Democrats say that in January they will elect San Diego Democrat Toni Atkins as the body’s first female president pro tempore.
Committee chairman Chris Holden told RTO Insider on Wednesday to refer questions on the status of the bill to de Leon’s office, which did not respond to emails and phone calls regarding the status of the bill.
“It is his bill,” Holden said. “We are waiting for him to come back with some amendments to address the issues that opposition had raised.” Speaking of the opposition last year, Holden said, “It was intense.”
Peter Miller, Western energy project director for the Natural Resources Defense Council, told RTO Insider that he thinks there is a good chance the bill will pass this year.
“There is uncertainty inside the building as to when it might move and how much attention de Leon might be able to pay to it,” he said. But he added there is a “tremendous grassroots effort” and public campaign taking shape in 2018 and “a lot of pressure” to approve the legislation.
“There is broad support, and that is going to show up in offices around the Capitol,” he said.
The two CAISO regionalization bills Holden sponsored last year, AB726 and AB813, are currently in the Senate Rules Committee and would likely not be be taken up until May or June, according to an Assembly staff member.
“We are still formulating what that bill should look like,” Holden said of the legislation that would explore regionalization. “It is important, and it is something we will be responding to with clear language, but right now we are formulating the language.”
There are many issues around CAISO regionalization, and complicating the picture is an effort by CAISO to extend its day-ahead market to the Western Energy Imbalance Market (EIM). (See CAISO Bid for Western RTO to Face Competition in 2018.) But an RTO would be different, including other states in its leadership and creating worries among some lawmakers that California’s aggressive pursuit of renewable energy could be diluted by other states with different goals and resources.
In a day that included several ceremonies, upon convening on Wednesday, the Assembly read the names of the victims of the 2017 wildfires, which have led to investigations into possible role of California utilities in the disasters.
The three grid operators serving the East Coast have so far weathered the extended cold snap gripping the region and are preparing to confront another round of plummeting temperatures — along with surging energy demand.
NYISO on Thursday reported strong performance on the 10th straight day of intense cold, with Arctic temperatures forecast for Upstate into the weekend.
“We’ve had no forced outages of the high-voltage direct current transmission system,” Vice President of Operations Wes Yeomans told reporters during a teleconference Thursday afternoon.
“The transmission system between central and eastern New York is fully loaded, as expected, bringing the less expensive energy from the western parts of the state to the high demand zones in and around New York City,” Yeomans said. In addition, the ISO was reaching out to transmission owners in the southeastern part of the state, which was bearing the brunt of a blizzard. (See NYISO Reports Adequate Capacity for Winter.)
Gov. Andrew Cuomo on Jan. 4 declared a state of emergency for the city, Long Island and Westchester County as a strong storm system barreled up the Atlantic Coast. Meanwhile, Upstate saw lake-effect snow, which the National Weather Service expects will be followed by subzero temperatures. A wind chill advisory warned that temperatures could feel as low as -42 F.
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PSEG Long Island on Thursday reported that about 3,818 of its approximately 1.1 million customers across Long Island and the Rockaways were without service. As of 4:20 p.m., the utility had restored service to more than 76% of the more than 16,574 customers affected by the storm.
NYISO Executive Vice President Rich Dewey said during the press conference that Albany had endured six consecutive days during which the low temperature fell below zero and the average was 10 F. Such weather is not unusual, but extended periods of it are, and the next couple of days could be the coldest, he said.
“We’re already predicting that we’ll be a couple hundred megawatts above Friday’s projected peak demand of 24,340,” Dewey said. All six nuclear units in the state were online and the storms were keeping the 100 MW of nameplate wind running strong, he said.
Nearly 50% of the New York’s generating fleet is able to switch to oil, which helps grid reliability, Dewey said, adding that operational enhancements made after the 2013/14 cold snap include increased surveys of generators to ensure they have adequate fuel supplies.
| NYISO
Yeomans said the ISO had seen very few generator outages so far and “thankfully no issue yet of a lack of fuel or emission limitations.”
Different generators have different rules and permits with the state’s Department of Environmental Conservation, and “some of the more binding restrictions are 30-day averages, so a generator can be using many of their credits but then turn around and start building them again when the weather turns normal,” Yeomans said.
New England Issues Cold Alert
New England’s bulk power system was also operating reliably on Thursday, ISO-NE spokesman Matt Kakley said.
As a precautionary measure, the RTO on Wednesday issued a Master/Local Control Center No. 2 alert in light of the impending winter storm as well as the expected extreme cold after the storm. The alert requires generation and transmission owners to stop any routine maintenance, construction or test activities on their equipment.
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ISO-NE also issued a Cold Weather Watch for Friday and Saturday as forecasts showed the return of extreme cold temperatures seen earlier in the week. The RTO issues a watch when extreme cold weather is in the forecast but it still expects a capacity margin of 1,000 MW or greater. (See New England Grid Prepared for Winter Reliability.) A slimmer capacity margin spurs a Cold Weather Warning, while a Cold Weather Event is called when a margin of less than or equal to 0 MW is forecast, warranting an emergency response.
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“Through this weekend, we expect to have sufficient capacity and fuel available to meet demand, barring unexpected outages,” Kakley said.
The cold weather continued to affect wholesale energy prices as well as the types of power plants being used to meet demand. High heating demand for natural gas causes pipeline constraints, resulting in high gas prices, which are driving the need for both oil- and coal-fired generation and boosting clearing prices. As a result, New England Internal Hub prices topped $300 on Thursday.
In general, a snowstorm doesn’t affect forecasted demand for power, unless there are local power outages caused by stormy conditions.
“In New England, we expect to have sufficient capacity and fuel available and expect to be able to weather the storm without running up against significant emissions limits, but concerns remain the same regarding fuel availability and emissions limits throughout this protracted cold spell and the rest of the winter,” Kakley said.
Snow and Ice in PJM
PJM issued a heavy load voltage schedule warning Thursday as a precautionary measure to help maximize power transfer capability and reactive reserve for the evening peak. Despite the warning, the RTO reported having maintained adequate power supplies and operating reserve margins during the cold weather. (See Frigid Weather Tests Grid Operators.)
The RTO reported no concerns with fuel availability and expected no reliability issues through the weekend. Extreme cold temperatures continued across its footprint Thursday, along with snow and ice in its eastern portion.
As of noon, PJM reported the preliminary peak demand for the cold snap as 136,125 MW set the morning of Jan. 3, which was projected to be the peak for the week.
PJM expects lower temperatures heading into the weekend and projects peak load will exceed 135,000 MW Friday morning.
Exelon and Public Service Enterprise Group will have to wait until the next session of the New Jersey Legislature for a vote on a bill to provide payments to the state’s nuclear fleet (S3560).
Several sources have confirmed that Rep. Vincent Prieto (D) declined to post the bill for a vote Thursday in one of his final acts as speaker of the Legislature’s lower house. The bill would provide upward of $300 million annually to operators of approved nuclear facilities for producing power.
PSEG has lobbied for the payments throughout the year, but the bill only materialized in December during Gov. Chris Christie’s lame duck session. Opponents — including business, consumer, environmental and power generation interests — feared it would be rushed through before Governor-elect Phil Murphy, a Democrat, takes office. (See NJ Nuclear Subsidy Bill Moves Swiftly out of Committee.)
PSEG has three nuclear reactors between the Salem and Hope Creek facilities, while Exelon owns 43% of the Salem units. PSEG says the units’ current profitability is attributable to sales hedges that expire within two years and that it will shut down the plants once they become unprofitable.
Opponents Cheer
Opponents cheered the news that the bill had stalled, calling it a victory for the state and praising Prieto, but keeping the door open for the issue to return later.
“Delaying action not only stands up to Chris Christie, it allows a new legislative session and a new governor to take the time necessary to carefully plan next steps and implement best practices if a bailout is needed,” Dale Bryk, chief planning officer at the Natural Resources Defense Council, said in an emailed statement. “It’s critical that any nuclear subsidies be done right so that New Jersey consumers, workers, communities and the environment are protected.”
“We applaud the Legislature for seeing through PSEG’s scare tactics and protecting our state’s future,” NJ Coalition for Fair Energy spokesman Matt Fossen said in an email. “The bottom line is that financial assistance should only be issued if it’s necessary, and the last few months proved that there was no reason to provide hundreds of millions of dollars to these already-profitable plants.”
The coalition, which includes Calpine, Dynegy, NRG Energy and the Electric Power Supply Association, on Wednesday released a sponsored economic study indicating the plants “have always been extremely profitable and will continue to be so through at least 2021 under current conditions.” The study foresees market rules changing and New Jersey returning to the Regional Greenhouse Gas Initiative “that will more than cover [the plants’] costs of production going forward” before the sales hedges roll off.
That study was performed by Energyzt, which last year produced a similar report showing that Dominion Energy’s Millstone nuclear plant in Connecticut would remain profitable into the next decade even without the state financial support being sought by the company. A Levitan & Associates study commissioned by Connecticut and released last month backed up that assessment. (See Millstone Likely Profitable Through 2035, Conn. Consultant Says.)
The Return of the Bill
But the New Jersey bill is likely to return in the next legislative session, NJ Spotlight reported, with new incentives for renewable and clean energy programs designed to win over current opponents who would stand to benefit.
Proponents aren’t giving up the fight and argue the issue needs to be addressed sooner rather than later.
“The fate of New Jersey’s nuclear generation is an urgent concern,” PSEG spokesman Michael Jennings said. “PSEG will continue to educate New Jersey’s legislators and policymakers on the economic threat facing the nuclear plants that serve our state — and the risk of increased air pollution, reduced resiliency, lost jobs and higher energy bills. These risks warrant greater attention.”
A federal judge last week handed FERC another defeat in its battles with traders over how courts review market manipulation allegations.
U.S. District Judge M. Hannah Lauck, of the Eastern District of Virginia, ruled Dec. 28 that Kevin and Rich Gates’ Powhatan Energy Fund is entitled to a de novo trial governed by the federal Rules of Civil Procedure and the federal Rules of Evidence rather than a more limited appellate-style review (Civil Action No. 3:15cv45).
Kevin and Rich Gates | Powhatan Energy Fund
The court noted its decision was consistent with rulings in five other district courts that have considered the issue, including FERC’s cases against Barclays Bank, City Power Marketing and Maxim Power.
‘Riskless’ Trades
In 2015, FERC ordered the Gates brothers and their associates to pay $34.5 million in penalties and disgorged profits for allegedly making riskless back-to-back up-to-congestion trades in PJM to profit on line-loss rebates. The defendants contend their trades were not riskless and thus not market manipulation. (See FERC Orders Gates, Powhatan to Pay $34.5 Million; Next Stop, Federal Court?)
Powhatan and its codefendants opted out of what the court called the “default option” of challenging their penalties before an administrative law judge and, upon appeal, the D.C. Circuit Court of Appeals. Instead, they chose an “alternate” option under the Federal Power Act, forcing FERC to issue a show cause order and asking the district court to “review de novo the law and the facts involved.”
FERC contended that the court’s review should be limited to the “the extensive factual and legal findings in the commission’s order and the substantial documentary and testimonial evidence contained in the administrative record.” Commission lawyers said the “administrative record” should be defined as “the materials filed by the commission’s Enforcement litigation staff and by respondents in the show cause proceeding as well as the commission’s orders issued in that proceeding,” and the commission’s penalty order.
“Should the court decide that additional fact finding is required on a discrete issue, the court is free to permit limited discovery, testimony, argument, etc., on that discrete issue,” FERC said. “Had Congress intended to require a trial, it could have done so … [and] has done exactly that in providing for trial de novo under other statutes.”
Due Process Concerns
But Lauck said FERC’s interpretation had “little basis in the statute or common sense” and could violate the defendants’ due process rights.
The court said that although FERC’s proposed “administrative record” includes almost 14,400 pages, “it does not include the entire investigative record, and the court has no ability to discern what products of the investigation FERC omitted or why.”
While Powhatan submitted arguments and evidence to FERC during the investigation, they were not permitted to take discovery, and the materials in the administrative record “were never tested under any evidentiary standard and may not be admissible under the federal Rules of Evidence,” Lauck wrote.
“Respondents have had, to date, no opportunity to compel any witnesses or documents or to cross examine any of the commission’s witnesses. Neither have they been able to test the reliability or veracity of the commission’s evidence through the evidentiary standards of either the federal Rules of Evidence or the [Administrative Procedures Act]’s requirement that ‘irrelevant, immaterial or unduly repetitious evidence’ be excluded in formal hearings.”
The court ordered FERC to refile its complaint, or an amended complaint within 30 days, with Powhatan responding within another 30 days.
Lauck declined to rule on Powhatan’s request for a jury trial, citing “the possibility that this action could be resolved [by settlement] before the court need decide the issue.”
Mixed Success in Courts
FERC hasn’t had an easy time prosecuting market manipulation, as defendants have become increasingly willing to make their cases in the courts.
Following a series of losses on procedural issues, FERC agreed in November to sharply reduce the penalty against Barclays over claims that it manipulated Western electricity markets a decade ago. (See FERC Settlement Cuts Barclays Market Manipulation Fine.)
In August, FERC closed its case against City Power over line-loss rebates for $2.7 million in fines after initially seeking more than $16 million. The settlement came after a U.S. district court rejected City Power’s motion to dismiss and FERC’s motion for summary judgment. (See Trader Agrees to Pay $2.7M in Win for FERC.)
Defenders of Illinois’ nuclear subsidy program faced harsh questioning Wednesday as a federal appeals court judge challenged their assertions that the zero-emission credits (ZECs) avoid federal pre-emption concerns. But the judge also expressed doubts about the standing of those challenging the program.
A three-judge panel of the 7th U.S. Circuit Court of Appeals heard oral arguments in Chicago from attorneys for the Electric Power Supply Association and Illinois customers, who oppose the law, and Exelon and the state, who defended ZECs legislation approved in 2016.
EPSA and retail ratepayers are asking the 7th Circuit to overturn a district court ruling that dismissed their challenge in July. (See Illinois Zero-Emission Credit Suit Dismissed.)
Under the law, Illinois ratepayers fund payments to supplement nuclear plants that don’t earn enough other revenue to cover their operating costs. Although the subsidies would make up the difference, the legislation was careful not to condition the subsidies on the generators selling into wholesale markets — an attempt to avoid the pitfalls that led the Supreme Court to reject Maryland’s attempt to subsidize construction of a gas-fired generator in its 2016 Hughes v. Talendecision.
The court ruled in Hughes that Maryland’s contract for differences with the generator could distort price signals in PJM’s annual capacity auctions, improperly intruding on federal jurisdiction over wholesale markets. (See Supreme Court Rejects MD Subsidy for CPV Plant.)
Judge Frank Hoover Easterbrook kept returning to the Hughes ruling, despite efforts by attorneys for the state and Exelon to differentiate their program.
“If you think you avoid Hughes by eliminating [the connection to wholesale markets], that again strikes me as fantasy,” Easterbrook said. “There is no world in which these nuclear plants produce energy, but it’s not sold onto the regional grid because that’s the world in which they melt down.”
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Exelon’s Matthew Price argued the plants don’t have to sell their output into wholesale markets. He pointed to MidAmerican Energy, which uses its 25% stake in Exelon’s Quad Cities nuclear facility near Cordova, Ill., to serve its customers in the region.
“When you sell at retail, you put your energy onto the grid and buy a transmission path to the user. That happens all the time,” he said. “I don’t think it’s pure fantasy that this distinction matters.”
Judge, State Clash
But Easterbrook pressed Illinois Assistant Attorney General Richard Huszagh to identify a nuclear facility that eschews wholesale markets. The question turned into a fiery exchange, with Easterbrook cautioning Huszagh on his wording and Huszagh repeatedly disagreeing.
Huszagh said plants could use bilateral contracts instead of markets to sell power but acknowledged that “I don’t think that’s likely.”
“I don’t think, as a practical matter, they could sell all of their output to retail customers. That seems unlikely given the volume” of output, he said.
“If it’s not likely, if there’s no nuclear plant in the country that does that, then the fact that the state has not formally said that ‘it depends whether you sell in the auction’ doesn’t matter. They are going to sell in the auction,” Easterbrook said. “Illinois may be entitled to do that, but I’m just perplexed at the denial that that’s what’s going on. It is what’s going on.”
“It is what’s going on, but that’s not the ultimate goal. It’s a necessary step on its way to achieving its environmental goals,” Huszagh responded. He noted that the U.S. goal during World War II wasn’t to “deliver a bunch of money to [General Motors] for making tanks, but it had to do that to accomplish its greater goal.”
“It’s fine to say: ‘Our aim is to defeat the signals being sent by that market and we’ve got a really good reason for doing that.’ That’s fine, but just go ahead and say that,” Easterbrook responded.
Huszagh called that characterization a “false choice,” saying that FERC can accommodate different state policies — even if they do affect price signals — without violating its mission under the Federal Power Act. He said it “doesn’t make any sense” to create a carbon trading market in Illinois that would only have a few suppliers from which ratepayers must buy.
“Now it sounds like the state of Illinois just is against competition all together,” Easterbrook said. “You need to be careful what you’re saying. Every word out of your mouth makes this case sound more like Hughes.”
“I disagree,” Huszagh replied.
“You may disagree, but that’s the effect you’re having on your audience,” Easterbrook shot back.
Huszagh contended that markets that don’t account for the social cost of pollution are not economically efficient “in the broader sense of the word,” but that it’s not FERC’s mission to promote those environmental concerns. “It’s the state’s … distinct regulatory authority over production to do so, and it may do so permissibly as long as it does not engage in wholesale rate setting,” he said. “And it’s not engaged in wholesale rate setting.”
“This is the same line of argument that the state made in Hughes and it didn’t work,” Easterbrook said.
“I disagree,” Huszagh responded.
Critique of Appellants
Judges Michael J. Reagan and Diane S. Sykes asked questions about the legal arguments but were less aggressive in their questions than Easterbrook, who was also critical of the appellants’ positions.
Easterbrook questioned why the court should act when EPSA has already asked FERC to subject the subsidized nuclear plants to the minimum offer price rule (MOPR) in capacity market auctions.
“The problem is the state has done something and the FERC so far has done nothing,” Easterbrook told Donald Verrilli, representing EPSA. “And you’re asking us, effectively, to predict that the FERC will do something.”
He asked Verrilli, a former solicitor general in the Obama administration, to explain how the ZEC program is different constitutionally from a carbon cap-and-trade program.
“The means requires the purchase of credits,” Easterbrook said. “That’s what a cap-and-trade scheme requires. … And the price of buying those credits will affect prices bid in the energy auction. Both the Illinois scheme and the cap-and-trade establish prices in a separate trading market that inevitably affect the price in the auction.”
“This scheme doesn’t establish prices in a separate trading market. … It’s just an additional payment for units of output sold into wholesale,” Verrilli said.
Patrick Giordano, representing Illinois customers, argued that Exelon pushed for deregulation of its in-state generation to seek better returns in regional markets and cannot now request reregulation because it doesn’t like the prices it’s getting. He favored the approach of the Department of Energy’s recent Notice of Proposed Rulemaking to address all nuclear plants “instead of one state singling out two favorite nuclear plants for subsidies and FERC reacting to it.”
Easterbrook largely ignored Giordano’s arguments and pressed him to explain why his clients have standing in the case given the Supreme Court’s Illinois Brick doctrine (431 U.S. 720), which established that only direct customers can complain about excessive energy charges. Giordano attempted to respond without specifically addressing the case.
“If you want to address Illinois Brick, that would be helpful. If you don’t know what Illinois Brick is because it hasn’t been raised by any of the parties, just say so,” Easterbrook said. “But filibustering won’t help.”
“I’ve read the case a long time ago, but it wasn’t raised,” Giordano said.
“That’s what I thought,” Easterbrook said.
Briefs Ordered
The court ordered supplementary briefs on three procedural issues that are due Jan. 17. The parties were asked to explain whether the court should defer to FERC’s primary jurisdiction; whether Anthony Star, the director of the Illinois Power Agency, can be held liable for enforcing the law if it’s found unconstitutional; and whether retail customers have standing given Illinois Brick.
The new year’s frigid temperatures resulted in a new winter peak demand for ERCOT Wednesday morning.
The ISO recorded a preliminary peak of 62.86 GW between 7 and 8 a.m., when freezing temperatures covered much of the state, exceeding Tuesday’s evening peak of 61.95 GW. Both broke the previous winter mark of 59.65 GW, set almost a year ago on Jan. 6, 2017.
South Texas snow | Goliad Farms
ERCOT had more than 70 GW of capacity available during the morning hours. The ISO in November projected a winter peak of just over 61 GW and said it would have as much as 81 GW of total resource capacity on hand to meet demand.
South Texas snowstorm | National Weather Service
Wholesale prices peaked at $70.02/MWh during the interval ending at 9:30 a.m. but were as low as $32.40 in the early morning hours. Tuesday’s prices peaked at $72.26 during the interval ending at 6 p.m.
ERCOT has not taken any extreme measures in meeting the winter demand.
Frigid conditions on the East Coast also brought PJM a peak load of 136.13 GW, the RTO’s highest winter demand since 2015. After a slight warming trend PJM, expects the extreme cold to return again later this week and has issued cold weather alerts for Friday and Saturday.
Lubbock Power & Light filed testimony with the Public Utility Commission of Texas in support of its proposal to move about 430 MW of load from SPP into ERCOT.
LP&L power plant | LP&L
The move would make LP&L the first to join ERCOT’s deregulated competitive market since it was created in 2002.
The PUC has scheduled a hearing on LP&L’s migration Jan. 17-18 in Austin.
Meeting Tuesday’s deadline, LP&L filed testimony from former FERC and PUC Chair Pat Wood III, Lubbock Mayor Dan Pope, LP&L Director of Electric Utilities David McCalla and three industry experts.
Wood, who was integral in helping create the ERCOT market and now runs his own energy infrastructure development business, said he felt compelled to speak out on the ISO’s benefits for LP&L’s customers. He said he was concerned “that the focus on selected details of this proposal is obscuring its significance.”
“We have in this proceeding the state’s third largest municipal utility requesting to move three-fourths of its load to ERCOT, and further, evidencing its intent to open its retail franchise to competition — something no other municipal utility has yet elected to do,” Wood said.
Pope said he is frequently asked by Lubbock citizens “to bring back competition for retail electric service.”
“Personally, I believe in the principles of competition, and there is no question in my mind that the citizens of Lubbock desire to be given the right to freely shop the Texas retail electric market for a provider,” Pope said.
The Lubbock City Council is expected to vote Jan. 11 on whether to conduct a study analyzing the effect of opening the retail market.
In his testimony, McCalla said giving customers a choice of retail providers was not a part of LP&L’s original proposal.
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“Customer choice is about more than simply economics,” he said. “It is about allowing customers to decide what percentage of renewable energy they purchase, to choose whether they want long- or short-term service, and to select from many other features and options that are available from a multitude of different retail electric providers.”
In September, LP&L filed its intention to integrate 430 MW of load with ERCOT by June 2021. That load is currently served through a wholesale contract with SPP member Southwestern Public Service; the contract expires May 31, 2021. ERCOT, SPP and LP&L have all filed studies in the case (Docket 47576), which began in 2015 when the municipality announced it intended to move 430 MW of its approximately 600 MW of load into ERCOT. LP&L is hoping for a decision before March, which will enable it to maintain its plan to integrate with ERCOT by June 2021, after extending a power purchase agreement with SPS. (See “LP&L Study: Production Costs Increase,” ERCOT BoD Briefs: June 13, 2017.)
New York Gov. Andrew Cuomo on Wednesday made clear that clean energy and the jobs it can create will continue to be a key part of his vision for the state’s future.
Governor Andrew Cuomo giving his State of the State speech | NY DPS
In his annual State of the State address, Cuomo called for the approximately $200 billion New York State Common Retirement Fund to “end any investment in fossil fuel-related activities,” saying “the future of the environment, the future of the economy and the future of our children is all in clean technology, and we should put our money where our mouth is.”
“Last year we announced one of the largest offshore wind projects in the nation,” Cuomo said. “This year I’m proud to announce we will be putting out at least two [requests for proposals] for at least 800 MW in offshore wind power, enough wind power to power 400,000 New York state households with clean energy. That’s a great and clean step forward.”
Anne Reynolds, executive director of the Alliance for Clean Energy New York, said the “announced commitment to a procurement in 2018 is a great step forward for growing this industry in New York. … A 2018 solicitation makes this real for New York.”
In his address last January, Cuomo set an offshore wind target of 2,400 MW by 2030. State policymakers are embracing offshore wind for both its utility-scale generation and its ability to be developed close to the major load centers of New York City and Long Island — as well as for its potential jobs. (See New York Seeks to Lead US in Offshore Wind.)
Statoil Wind Lease Area | Statoil
Norway-based Statoil in December 2016 bought the first offshore wind lease for New York, a nearly 80,000-acre site off the Rockaways in Queens large enough to generate up to 1 GW of power. Statoil dubbed the project Empire Wind and is working to sign a power purchase agreement with a U.S. utility.
South Fork Wind Farm | Deepwater Wind
Long Island could see the first offshore wind project in the state with the 90-MW South Fork Project off Montauk, which was approved by the Long Island Power Authority a year ago. Developer Deepwater Wind says construction could start as early as 2019, and the wind farm could become operational as early as 2022.
Easier Storage
The governor’s office on Tuesday released Cuomo’s clean energy jobs and climate agenda, which includes cutting emissions from high-polluting peaking plants and directing the NY Green Bank to invest $200 million toward meeting an energy storage target of 1,500 MW by 2025. Cuomo’s Reforming the Energy Vision policy includes a Clean Energy Standard mandate to generate 50% of the state’s electricity from renewable sources by 2030.
In November, Cuomo signed legislation requiring the Public Service Commission to establish targets for energy storage by early 2018. Cuomo is now also directing the New York State Energy Research and Development Authority to invest at least $60 million in storage demonstration projects and efforts to reduce barriers to deploying energy storage, including permitting, customer acquisition, interconnection and financing costs. (See NYISO Readies Market for Energy Storage, State Targets.)
A NYISO report in December laid out a three-phase plan for opening its wholesale markets to storage through integration, optimization and aggregation with other distributed energy resources. The ISO distinguishes between storage in front of the meter and behind the meter, with the former more likely to participate in wholesale market transactions, although BTM storage could become a wholesale player when aggregated with other distributed resources. (See New York Sees Storage in Retail and Wholesale Markets.)
In his speech, Cuomo also announced a zero-cost solar program for 10,000 low-income New Yorkers and directed the establishment of a state energy efficiency target by April 22 (Earth Day).
New York State of the State speech audience | NY DPS
He also said New York will reconvene a scientific advisory committee on climate change that was disbanded last year by the Trump administration, and also adopt regulations to close all coal-fired power plants within the state. As cochair of the U.S. Climate Alliance and in collaboration with partners, Cuomo said he will reconvene the advisory committee to “continue its critical work without political interference and provide the guidance needed to adapt to a changing climate.”
Clean Jobs, Clean Air
NYSERDA also plans to invest $15 million in clean energy job development and infrastructure advancement to train workers for offshore wind construction, installation, operation, maintenance, design and associated infrastructure. Cuomo is directing NYSERDA to work with Empire State Development and other state agencies to promote development of offshore wind port infrastructure to jumpstart development.
New York is one of the nine Regional Greenhouse Gas Initiative states that set out in 2013 to cut power plant emissions 50% by 2020. Last August, other RGGI states agreed to answer Cuomo’s call to lower the emissions cap by an additional 30% by 2030.
Cuomo will direct the state’s Department of Environmental Conservation to regulate beyond RGGI requirements in order to cover power plants under 25 MW, many of which are smaller but highly polluting peaker units that operate intermittently during periods of high electricity demand. The department will also adopt regulations banning coal-fired generation in the state’s power plants by 2020.
Heather Leibowitz, director of Environment New York, said, “The message in today’s State of the State was clear: By reducing pollution and shifting to clean energy, we can grow our economy while leaving a healthier, safer planet for our children.”
Dominion Energy on Wednesday said it will buy SCANA for $7.9 billion in a stock-for-stock transaction, securing a utility troubled by a botched nuclear project.
SCANA, which owns South Carolina Electric & Gas, has been under financial pressure since it scrapped the two-reactor expansion of its V.C. Summer nuclear plant last July after spending about $9 billion on the effort. The nearly decade-long project fell victim to design flaws, cost overruns, construction delays and the bankruptcy of lead contractor Westinghouse Electric.
Dominion’s $7.9 billion acquisition will include an additional $6.7 billion in assumed debt, valuing the sale at about $14.6 billion. The Virginia-based utility is offering reduced rates to SCE&G customers and a partial refund of the incomplete expansion at the Summer plant.
SCANA shareholders will receive slightly more than two-thirds of a Dominion share for each share they own, valuing the stock at about $55.35. SCANA shares lost almost half their value over the past year, falling to under $40/share early this week. Hours after the deal was announced, SCANA shares rallied from $39 to $48, while Dominion fell from $80 to $77.
Dominion Goes South
The resulting company would operate in 18 states, serving about 6.5 million regulated customers. The companies said the sale would be a strategic union that would help Dominion solidify a presence in expanding Southeast markets.
“SCANA is a natural fit for Dominion Energy,” Dominion CEO Thomas Farrell II said. “Our current operations in the Carolinas — the Dominion Energy Carolina Gas Transmission, Dominion Energy North Carolina and the Atlantic Coast Pipeline — complement SCANA’s … operations. This combination can open new expansion opportunities as we seek to meet the energy needs of people and industry in the Southeast.”
SCANA has about 1.6 million electric and natural gas residential and business accounts in the Carolinas. Dominion currently operates two solar farms in South Carolina and a 1,500-mile network of gas pipelines purchased from SCANA two years ago for $497 million.
SCANA would become a Dominion subsidiary, with Dominion pledging to maintain the utility’s South Carolina headquarters and protect SCANA’s 5,000-plus existing jobs until 2020. Dominion has also promised to take up SCANA’s plans to complete the purchase of the $180 million, 540-MW Columbia Energy Center natural gas-fired plant in Gaston, S.C., to fill energy needs expected to be met by an expanded V.C. Summer.
V.C. Summer project | South Carolina Electric & Gas Co.
“Joining with Dominion Energy strengthens our company and provides resources that will enable us to once again focus on our core operations and best serve our customers,” said SCANA CEO Jimmy Addison, who until Monday was SCANA’s chief financial officer. He replaced former CEO Kevin Marsh, who retired in the face of federal and state scrutiny of the failed V.C. Summer project.
In response to concerns about the nuclear project, Dominion is offering $1.3 billion in refunds to SCANA customers, amounting to about $1,000 each. Dominion also claims the sale will cut the time that customers will be on the hook for paying for the unfinished reactors from 60 years to 20 years. The company has also promised to reduce rates for SCE&G customers by about 5%, or $7/month.
Customers are currently paying about $27/month — or 18% of their monthly bills — to finance the unfinished reactors.
Dominion is proposing to cut refund checks to customers based on 2017 electricity usage within 90 days of the finalized sale. Farrell said the move will “guarantee a rapidly declining impact from the V.C. Summer project” and called the proposed refunds as the “largest utility customer cash refund in history.”
However, consumer advocates are contending that at least some of the proposed 5% rate reduction is already guaranteed to customers to reflect company gains from the corporate tax cuts recently passed by the U.S. Congress. Last week, the South Carolina Office of Regulatory Staff requested that state utilities draw up plans to share their tax savings with customers.
Sale Requires Continuation of Base Load Review Act
Another possible sticking point: Some South Carolina lawmakers claim the proposed deal is meant to compel South Carolina lawmakers to preserve the controversial Base Load Review Act, the 2007 law that allows SCE&G to continue to pass onto customers the costs of nuclear reactors that will never produce a kilowatt of power. The deal presumes that SCANA customers will continue to pay the reduced rate under the law for 20 years.
Meanwhile, federal and state investigators are reviewing whether the law’s provision to charge customers for abandoned generation projects is reasonable, and South Carolina lawmakers next week will begin deliberating legislation that could halt customer collection altogether on the scuttled project (S 0754).
Last month, SCE&G formally asked the Nuclear Regulatory Commission for permission to withdraw its operating license for the reactors, a move intended to show the company has entirely given up on the project and is eligible for a $2 billion tax write-off.
The South Carolina Public Service Commission last week denied SCE&G’s request to dismiss two proceedings related to the failed attempt to expand V.C. Summer. One case sought to eliminate charges that the SCANA subsidiary’s customers are paying for the failed project, while the other sought refunds for what customers have already paid. The PSC has said it will hold a hearing this year to determine the merits of eliminating the charges and granting refunds.
Governor Reacts
South Carolina Gov. Henry McMaster, who has supported complete customer refunds of the nuclear project costs, said the proposed transaction represented “progress” but that there was “more work to be done,” namely selling off state-owned electric and water utility Santee Cooper, SCANA’s project partner in the unfinished reactors.
“Under the proposed agreement between SCANA and Dominion Energy, SCE&G ratepayers will get most of the money back they paid for the nuclear reactors and will no longer face paying billions for this nuclear collapse. But this doesn’t resolve the issue,” McMaster said in a statement. “Over 700,000 electric cooperative customers face the prospect of having their power bills sky rocket for decades to pay off Santee Cooper’s $4 billion in debt from this. The only way to resolve this travesty is to sell Santee Cooper.”
Dominion and SCANA expect the deal to close this year, although the companies still require approval from several agencies, including FERC, NRC, the Federal Trade Commission, the Department of Justice and South Carolina, North Carolina and Georgia regulators.
The companies have set up a special website explaining the acquisition to SCANA customers at dominionenergysouth.com.
NYISO on Tuesday asked FERC to deny Entergy’s request that the commission clarify the deadline for the ISO to complete a final market power review for the deactivation of the Indian Point nuclear plant (ER16-120, EL15-37).
At issue is the commission’s acceptance in November of NYISO’s revisions to its reliability-must-run program, adding a 365-day notice period for a generator to notify the ISO that it plans to retire. (See FERC Approves NYISO Reliability-Must-Run Plan.)
Indian Point Nuclear Plant | Entergy
In a Dec. 18 filing with FERC, Entergy noted that NYISO failed to include a 120-day market power review deadline that was in an earlier filing. The company contended that without a clear deadline for review, its 2,311-MW Indian Point plant lacked certainty about authorization to exit the market. (See Entergy Asks FERC to Clarify Indian Point Retirement Process.) The company is seeking a March 13 deadline for NYISO to complete a market power study for the closure. Units 2 and 3 at the plant are slated to close in 2020 and 2021, respectively.
In its Jan. 2 response, NYISO said that requiring it “to complete physical withholding analyses years in advance of generator deactivation would clearly be unreasonable and unjustified on equitable or policy grounds.” The ISO argued that market conditions could change “dramatically” over a two- or three-year period, “as could a generator owner’s business plans as well as the plans of other generators.”
Indian Point Nuclear Plant Control Room | Entergy
NYISO also contended that its previous references to completing market power studies within 120 days only applied to generating units closing within one year of providing notice.
“This focus on generators deactivating in 365 days, and the NYISO’s rationale for proposing this time frame as the minimum notice period, is made abundantly clear in all of the NYISO’s stakeholder presentations and all of its filings in this proceeding,” the ISO said.
The Independent Power Producers of New York also on Tuesday filed in support of Entergy’s request for clarification. IPPNY argued that without a clear deadline for the final market power assessment, “a generator owner will have difficulty planning when its generator will be able to deactivate. … NYISO’s completion of the final market power assessment may effectively operate as a bar on a generator’s deactivation, which is entirely contrary to [FERC’s] goal that generator owners know with certainty when they can deactivate their resources.”
An ISO report in December found that new gas-fired and dual-fuel generation coming online in the next few years, led by the 1,020-MW Cricket Valley plant in Zone G, will be enough to maintain reliability after Indian Point shuts down completely. (See New Builds to Cover Indian Point Closure, NYISO Finds.)
