Brian Lloyd is only the PUC’s second executive director and has held the position for slightly more than seven years. In a letter to staff, Lloyd said his departure would ensure a smooth transition to a new director and allow the commissioners “sufficient time to be deliberate in considering the applicants they will have for this position.”
“I have felt very strongly over the past several months that God has something else that he wants me to move onto, and while it is scary having absolutely no idea what that is, I’ve been comforted much over the holidays with reminders to place my trust there,” Lloyd wrote.
“The most difficult part of this decision is how much I enjoy working with all of you on issues critically important to Texas and the high degree of integrity and ethical standards that I believe is ingrained in our culture here,” he said.
Lloyd’s resignation creates two vacancies among the PUC’s senior leadership. Communication Director Terry Hadley retired from the commission just before the new year. Hadley had been with the PUC since Texas’ electric restructuring legislation was signed into law in 1999.
The PUC is also entering 2018 with a new chair (DeAnn Walker) and a new commissioner (Arthur D’Andrea), who replaced the commission’s longest-serving commissioners (Donna Nelson and Ken Anderson) last fall.
As executive director, Lloyd oversees the PUC’s day-to-day operations and management, including developing its strategic plan, directing staff analysis of contested proceedings and rulemakings, and developing and implementing the agency’s budget. Lloyd also coordinates the commission’s interaction with other state agencies and represents it at the Texas Legislature and other forums.
Lloyd has served in roles of increasing responsibility during his 19 years in electricity and telecommunications market design, restructuring and deregulation, as well as areas of electric reliability and assessing the impacts of federal environmental policy on competitive and regulated electricity markets. Before joining the PUC in September 2010, he was Gov. Rick Perry’s deputy director of budget, planning and policy.
Lloyd holds a bachelor’s degree in economics from Louisiana State University and a master’s degree in economics from the University of Texas at Austin.
California regulators will this week vote on a proposal to replace out-of-market contracts between CAISO and Calpine, saying the ISO failed to follow its established procurement process and possibly distorted its electricity markets.
The California Public Utilities Commission’s proposed Jan. 11 decision would replace the reliability-must-run contracts for Calpine’s Metcalf, Yuba City and Feather River power plants in Northern California with energy storage and fast-acting “preferred resources” by 2019. Pacific Gas and Electric would procure the resources, which must be eligible to come online before the RMR contracts are renewed for 2019, the proposed decision says.
The commission noted that the RMR contracts were developed outside of its resource adequacy (RA) process and that CAISO’s backstop Capacity Procurement Mechanism (CPM) was not initiated before awarding the contracts.
“Lack of competition … can lead to market distortions and unjust rates for power,” the CPUC said. “It is because of this concern that the commission is exercising its broad procurement authority with this resolution to authorize PG&E to conduct the solicitation for resources that can effectively fill local deficiencies and address issues identified.”
The CAISO Board of Governors in November reluctantly approved the Metcalf RMR agreement, which was developed in an expedited timeline. (See Board Decisions Highlight CAISO Market Problems.) The board approved the Yuba City and Feather River RMRs last March, drawing some stakeholder criticism because such out-of-market payments indicate the market might not be sending appropriate price signals. (See CAISO RMRs Win Board OK, Stakeholders Critical.)
Additionally, in a Dec. 22 market notice, CAISO said it had used its CPM backstop authority for PG&E’s 510-MW Moss Landing plant in the South Bay-Moss Landing sub area and for two units at San Diego Gas & Electric’s Encinas plant in Carlsbad.
The South Bay-Moss Landing Sub Area near Silicon Valley | CAISO
An RMR contract differs from a CPM designation in that it is involuntary for the generator, which receives a negotiated contract rate for a year. The voluntary CPM falls under a market-based price up to a cap and is riskier because the contracted megawatts can vary from month to month.
Calpine says RA capacity prices and CPM are not sufficient to sustain the plants, a claim that the CPUC has questioned. The company told CAISO in November 2016 that it planned to terminate generator interconnection agreements for the Feather River, Yuba City, King City and Wolfskill plants. In June, it told CAISO it was considering taking the 580-MW Metcalf off ISO dispatch.
In the case of Metcalf, Yuba City and Feather River, “Calpine did not enter into any bilateral RA contracts for 2018,” the CPUC said. “Instead, the company elected to communicate to the CAISO that it was planning to make these resources unavailable for CAISO dispatch unless it was awarded an RMR contract.” According to the CPUC, Calpine has said that RA capacity prices are not adequate, and that the CPM planning period does not allow sufficient time for maintenance, budget and other planning considerations.
Further complicating the situation is the fact that CAISO and Calpine are butting heads over the terms of the Metcalf, Yuba City and Feather River RMRs. CAISO and PG&E filed protests regarding the contract terms Calpine filed with FERC, which last month set the matter for settlement talks. (See FERC Orders Hearing, Settlement Talks for Calpine RMRs.)
Having noted misalignments between its processes and the CPUC’s RA program, CAISO last October launched an initiative to collaborate with the CPUC to address possible reforms. In its 2017 policy catalog, the ISO said that a rapid transformation of the fleet to more variable energy resources “is exposing inadequacies in the current resource adequacy framework.”
“I always call this a tale of two RA programs,” Carrie Bentley of Resero Consulting — which frequently represents the Western Power Trading Forum in ISO matters — told RTO Insider. She noted that the CPM model has more risk than an RMR, and that the CPUC prefers market-based outcomes rather than RMRs.
Bentley noted that the growth of community choice aggregators (CCAs) has also compounded the problem because they procure resources on an incremental basis, rather than for the full output of a plant, which is not preferable for power plant owners. CCAs allow local governments to do their own electricity procurement and have been marketed heavily in the San Francisco Bay Area as clean energy alternatives to traditional utilities.
“I think it’s a huge issue,” Bentley said. “You can’t count on building a book that way if you are a power plant owner.”
The CPUC is expected to address the CCA issue at its Thursday meeting with a recently drafted decision that would make CCAs subject to RA requirements. The proposal would better align CPUC and CAISO resource planning, the commission said. (See California Proposes Resource Adequacy Obligations for CCAs.)
CCAs have grown rapidly in California since the launch of Marin Clean Energy in 2010. Over the five following years, two new CCAs were launched serving 135,000 customers. In 2016 and 2017, 12 communities either launched new CCAs or filed implementation plans, the CPUC said.
SPP’s market-to-market (M2M) process with MISO again resulted in a large payment to SPP for November operations. The SPP Riverton-Neosho-Blackberry flowgate on the Kansas-Missouri border was once again responsible for the bulk of the payment.
Including November’s total of $3.9 million, the permanent flowgate has resulted in $15.3 million of M2M payments to the RTO from MISO, accounting for almost half of the $32.7 million SPP has or will receive since the M2M process began in March 2015.
The flowgate was binding for 296 hours in November after binding for 329 hours in October, when it racked up a $5.1 million charge to MISO. The flowgate is responsible for more M2M payments between the two RTOs than the next seven flowgates combined.
| SPP
RTO staff told the Seams Steering Committee on Jan. 3 that they are analyzing data to determine what kind of project would address the historical congestion in the area and whether it would be worth forgoing the M2M payments.
“We may be getting $5 million a month from MISO, but how is that impacting load in the area?” SPP’s Will Ragsdale said. “We want to understand the impact on the market as a whole, not just this one piece of data.”
Ragsdale promised to bring results of the analysis to the February meeting.
As was the case in October, loading because of high wind combined with nearby outages produced the constraint. The flowgate is in the Empire District Electric and Westar Energy control zones.
With no joint study scheduled this year, the SPP-MISO Interregional Planning Stakeholder Advisory Committee (IPSAC) will conduct an annual issues review with stakeholders Feb. 27 in Little Rock, Ark.
SPP Interregional Coordinator Adam Bell told the SSC that the IPSAC will review transmission issues identified by the RTOs or stakeholders, regional expansion plans and regional planning coordination. SPP and MISO have yet to agree on a single interregional project in two attempts.
Bell invited stakeholders to submit transmission issues and feedback on the RTOs’ joint planning by Jan. 29.
“It’s not limited to transmission issues,” Bell said. “We’ll listen to process improvements, lessons learned from joint studies and ideas on future planning.”
Under terms of the RTOs’ joint operating agreement, the IPSAC will meet every year that there is no joint study.
SPP staff will also meet with Associated Electric Cooperative Inc. in the first quarter to review the scope for a 2018 joint study.
SPP Sets New Winter Peak Demand Record
Last week’s frigid temperatures across the nation and in SPP’s footprint resulted in a new winter peak demand for the RTO of 41,014 MW on Jan. 2.
The RTO, with a 14-state footprint that stretches from East Texas to the Dakotas, issued a cold weather alert through Jan. 4. Some of the RTO’s gas units had difficulty procuring fuel and switched to more costly oil, but a spokesman said SPP had not “encountered anything unmanageable.”
Clean Line Energy Partners said Thursday that market realities led the company to sell its Oklahoma assets to NextEra Energy and put a temporary halt on its Plains & Eastern Clean Line project.
In the meantime, Clean Line founder and president Mike Skelly told RTO Insider, the company will focus on its four other long-haul HVDC projects.
“We’re adapting to the headwinds,” Skelly said. “You have to adapt.”
Clean Line announced in December that NextEra had purchased the assets of the Oklahoma portion of its $2.5 billion Plains & Eastern project, which was to deliver 3.5 GW of wind energy to Memphis, Tenn., and the Tennessee Valley Authority. (See Clean Line Sells Okla. Portion of Plains & Eastern to NextEra.)
The deal was sealed after it became apparent to Clean Line that TVA had little appetite to complete a six-year-old memorandum of understanding to purchase the project’s wind power. Late last year, just weeks after TVA said it was still studying whether to sign the contract, agency President Bill Johnson said the Clean Line project didn’t make economic sense, given TVA’s flat demand and ample generating capacity.
“We fund these projects with investor dollars, not ratepayer dollars,” Skelly said. “We were sort of hoping TVA would anchor this line by buying energy.”
Skelly said Clean Line began considering its options when it was approached by renewable energy powerhouse NextEra regarding its Oklahoma assets. The purchase includes Clean Line’s Oklahoma right of way.
“While getting that piece of the line built wasn’t everything we wanted to get done, it’s a significant thing,” Skelly said. “Now, the biggest renewables provider in the country owns this [400] miles of right of way. We believe that will enable them, or them working with others, to build a few gigawatts of wind. Our goal has always been to get more gigawatts on the grid, and that’s a positive outcome.”
Clean Line had intervened in Public Service Company of Oklahoma’s (PSO) $4.5 billion Wind Catcher project, which is currently before the Oklahoma Corporation Commission (Docket 17-267). Clean Line Executive Vice President Mario Hurtado called the Wind Catcher proposal “a good idea” in written testimony and suggested that PSO could take advantage of the easements his company has already secured.
“Schedule delays could jeopardize the size of the benefit to ratepayers from the production tax credit,” Hurtado said. “The Plains & Eastern project could substantially mitigate the cost and schedule risks for Wind Catcher.”
NextEra did not respond to a request for comment on its plans.
Plains & Eastern Clean Line Project Schematic | Clean Line Energy Partners
Clean Line has not entirely given up on Plains & Eastern, which has approval from the Tennessee Regulatory Authority and a “record of decision” from the U.S. Department of Energy to participate in its development under Section 1222 of the 2005 Energy Policy Act. (See DOE Agrees to Join Clean Line’s Plains & Eastern Project.)
Clean Line has held on to the project’s Arkansas right of way, although the company has encountered heavy opposition from lawmakers and landowners in the state. However, in the waning days of 2017, it also received a favorable ruling from a federal judge in a lawsuit that confirmed DOE’s participation in the project.
“We’ve been working on this thing for eight years,” Skelly said. “We’ve been working with and trying to convince the TVA and other Southeastern utilities of the merits of low-cost renewable energy. It’s been a long, slow process.”
Asked whether the decision to sell its Oklahoma assets was driven by a combination of TVA’s reluctance and the need for funding, Skelly said, “That’s not an unfair conclusion.”
“It’s more the market than the financing,” he said. “Our read of the market is that … it doesn’t appear [the Southeastern utilities] are going to do large renewable purchases in the short term. We would argue their customers want it, it’s cost effective, it’s technically feasible … we think there’s demand, but they don’t want to [meet it], and that’s their choice.”
Clean Line will now turn its attention to the proposed 780-mile Grain Belt Express, a $2.3 billion initiative that would deliver 4 GW of wind power from western Kansas through Missouri and Illinois to the Indiana border. The project is working its way through the appellate court process in Missouri, aided by former Gov. Jay Nixon. (See Unfazed by Obstacles, Clean Line’s Skelly Focuses on Future.)
“It’s been a somewhat protracted legal process, but we anticipate that will be sorted out second quarterish,” Skelly said.
Clean Line’s other three projects include:
The Rock Island Clean Line, a 500-mile project from northwest Iowa to Illinois, delivering 3.5 GW of wind energy. The project was originally expected to be operational in 2017. But on Sept. 21, the Illinois Supreme Court rejected the Rock Island application because Clean Line held only an option agreement on a parcel for a converter station — rather than a completed purchase agreement — when it applied to the Illinois Commerce Commission. The company said the ruling will cause “great delay” for the project.
The Centennial West Clean Line, a 900-mile project delivering 3.5 GW of renewable energy from New Mexico and Arizona to California. The company had expected construction to begin in 2017 and be operational in 2019. Development has slowed down while the company works on its other projects.
The Western Spirit Clean Line, a 140-mile project complementing the Centennial West project, delivering 1 GW of renewable power from east-central New Mexico to markets in the western U.S. Clean Line acquired the project, originally named Power Network New Mexico, in 2013. Construction, which will take about one year, could begin by the end of 2018.
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.
| N WS
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.
| ISO-NE
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.
| NWS
“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.”
| EPA
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.
