Massachusetts Attorney General Maura Healey and consumer group Public Citizen are raising market power concerns over a Japanese company’s plan to buy three gas-fired power plants in New England.
The investment firm Stonepeak asked FERC June 1 for approval to sell two units at Canal Generating Station in Sandwich, Mass., totaling 1,457 MW, and another 160-MW unit in Bucksport, Maine, to JERA, a joint venture between two Japanese utilities (EC22-71).
The AG and Public Citizen say the acquisition would give JERA, which already owns 50% of two other gas units totaling more than 400 MW in Massachusetts, too large a share of the generation market.
“The proposed transaction would by definition result in some degree of increased concentration of power generation ownership in New England and New York, and significant concentration of power generation capacity ownership in the import constrained SENE Capacity Zone of ISO-NE,” Healey wrote in a comment.
After the transaction, JERA would own more than 18% of the capacity cleared in the Southeastern New England zone.
The application also didn’t consider whether JERA would try to get reliability-must-run or other out of market payments, Healey wrote.
She called on FERC to comprehensively review the application — and to take its time by rejecting a request from the companies for expedited consideration and approval by Aug. 1.
The deal “looks like a pretty big bet to make lots of money off ISO-NE’s capacity market, and likely prolong the life of some fossil fuel power plants,” Public Citizen’s Energy Director Tyson Slocum wrote in an email to RTO Insider.
Slocum said that the deal raises questions about the concentration of voting in ISO-NE’s NEPOOL stakeholder process.
“Since NEPOOL membership conveys the ability to influence market design in ISO-NE (and therefore directly impacts rates), details on how exactly JERA plans to participate as a voting member in NEPOOL post-transaction is needed to determine whether the transaction is in the public interest,” the protest says.
Public Citizen says the company should disclose its plans for NEPOOL representation, as well as sharing the transaction price.
“We object to the confidential treatment of the sales price of the transaction, and ask the commission to release it,” Slocum wrote. “The purchase/sales price of power generation transactions reveal information essential to the public interest about the buyer’s expectation of economic return of the asset.”
Defending the Deal
In the application, the companies laid out why they believe the acquisition is not a threat to competition, using analysis from consultant Julie Solomon of Guidehouse.
Solomon found de minimis effects on competition in the market, while acknowledging that it would increase the market share of generators affiliated with JERA to 6.4% in ISO-NE and 18% in the Southeast zone.
“Public Citizen does not raise any issues that would prevent the commission from authorizing the transaction as requested in the application,” the filing says. “Instead, Public Citizen seeks to use this proceeding to address other matters, including by means of imposing conditions that have no place in a proceeding under [Federal Power Act] Section 203.”
Residential customers will be charged about $55/month to participate in community solar programs in Dominion Energy (NYSE:D) territory in Virginia, a fee that solar advocates say will cripple the nascent program.
The Virginia State Corporation Commission on July 7 approved the $55.10 monthly minimum fee for residential customers using 1,000 kWh/month (PUR-2020-00125).
Low-income customers will be exempt from the minimum. But others will be dissuaded from participating because the fee is among the highest in the country, solar supporters say.
“If shared solar is going to work, Virginians need to pay less than $660/year just to be plugged into the grid before netting a single electron off it,” tweeted Sen. Scott Surovell (D), who co-sponsored the bipartisan 2020 bill establishing the shared-solar program (HB 1634/SB 629).
The Coalition for Community Solar Access (CCSA) called the commission’s order “an anti-consumer, anti-business” ruling “that does not align with the legislative intent and undermines the economics and accessibility of the shared-solar program for participating subscribers, while perpetuating a culture of egregious overcollections by Dominion Energy.”
“The SCC’s decision will decrease crucial investments in the commonwealth’s economy and lock out thousands of consumers and businesses from accessing local, clean energy generation,” the group said in a statement.
The commission’s order accepted the minimum monthly fee recommended by a commission hearing officer in February. It is substantially less than Dominion’s proposed charge but more than double that urged by CCSA. (See Advocates Offer Compromise on Minimum Charge for Va. Shared Solar.)
The commission said the fee includes costs “relevant to ensure subscribing customers pay a fair share of the generation, transmission, distribution and fixed costs of providing electric service.”
The minimum charge comprises fixed customer ($6.58) and administrative ($1) charges and volumetric costs, including non-bypassable generation charges ($3.37); base distribution charges ($19.26); distribution rate adjustment clause (RAC) charges ($4.62); base transmission charges ($9.70); and transmission RAC charges ($10.59).
The order also adopted Dominion’s proposed bill credit of 11.7650 cents/kWh for residential customers, 7.1200 cents/kWh for commercial customers and 5.9010 cents/kWh for industrial customers. The commission said the bill credit rates reflect generation, transmission and distribution revenues and “generally offsets the full costs typically included in the customer’s bill.”
The 2020 legislation required the SCC to approve a shared-solar program of 150 MW, with a minimum requirement of 30% low-income customers. The program can be expanded by 50 MW once the 30% low-income participation threshold is reached.
Dominion said that a residential customer who consumes 1,000 kWh should receive a minimum bill of $74.90 (distribution service charges: $29.45; transmission service charges: $20.29; generation balancing service charges: $25.16), not including administrative overhead costs, which it estimated at $10 to $20/month per customer. Anything less than that would result in cost shifts to nonparticipating customers, the utility said.
Commission staff proposed two alternatives: $10.95/month, which excludes transmission and distribution charges, or $55.10/month, which includes them. “Staff believes that, ultimately, the determination of the appropriate minimum bill is a policy question for the commission’s determination,” a staffer testified in a hearing last year.
Dominion Energy says it has received applications for 11 shared solar projects totaling almost 43 MW. | Dominion Energy
Former Texas regulator Karl Rabago, CCSA’s witness at the hearing, said, “Dominion’s approach appears specifically designed to make shared-solar subscription unattractive to potential subscribers and, therefore, renders the shared-solar program unworkable.”
In a letter to the SCC in April, Surovell, Sen. Emmett Hanger (R) and Del. Rip Sullivan (D) protested the hearing examiner’s recommendation, saying “we did not pass legislation to create a program that exists in name only.”
Surovell said the commission’s ruling “highlights why the SCC vacancy is critical.”
The SCC currently has only two members after Democrats were unable to win a full term for Angela Navarro, who was appointed by former Gov. Ralph Northam to replace Mark Christie when he left to join FERC. Navarro herself left in March.
Dominion did not respond to a request for comment Monday. The company reports having received applications for 11 shared-solar projects totaling almost 43 MW.
By Christy Walsh, Natural Resources Defense Council
Christy Walsh | NRDC
The climate crisis is putting the electricity system at risk. Our aging grid is straining to handle the stronger storms, hotter heat waves, extended drought and extreme flooding many parts of the U.S. are already seeing.
With these increasing threats, grid operators will need to use all the tools they can — especially demand response, energy efficiency and imports from surrounding areas — to curb stress on the system and limit the threat of blackouts.
But as important as those actions are, they are not enough. Congress also must act now to invest in a clean, resilient and affordable power grid.
Given the climate crisis before us, the conclusion is clear: We must transition away from fossil fuels that contribute to climate change and invest in a grid that’s resilient to storms, high heat and flooding. A recent NRDC policy brief shows how legislation under consideration in Congress would enhance reliability by:
expanding long-distance transmission lines;
encouraging more solar and wind power, especially in energy justice communities;
curbing energy demand through weatherization and energy efficiency programs;
investing in communities where coal mines or fossil fuel plants are closing; and
spurring the sale of electric vehicles, which can double as backup batteries for customers.
Fossil fuel defenders have been attempting to blame wind and solar for some of the strains to the grid we have seen this year, but that’s just ridiculous. As has been made clear time and time again, no single power source is perfect. Coal piles freeze, gas lines stop flowing, and nuclear plants shut down before a hurricane makes landfall.
And it’s not just the heat and storms: A recent NERC assessment noted that stressed supply chains are crimping coal supplies.
Congressional action, coupled with decisions by states, public service commissions, grid operators, and federal regulators can spur renewables, energy efficiency, demand response, electric storage, and new transmission lines to get us the clean, reliable, resilient electrical system we need.
What we all should be able to agree on is that we need to invest in a larger power grid. The bigger, wider and more flexible the grid, the more able it will be to respond to whatever comes its way.
The right transmission and interconnection rules are key to creating a better grid for years and decades to come.
In the MISO area and in PJM, the grid serving the mid-Atlantic, thousands of solar and wind projects are ready to be built yet remain in limbo. Consider the more than 100,000 MW of clean energy in MISO just waiting to supply the grid. That’s more than halfof total installed generating capacity in the MISO region. These and future additions can replace retiring fossil fuel generators. Even taking into account that some of this generation will not be built, getting these and future additions on line more quickly is vital to achieving a reliable energy transition and lowering energy costs.
We also need more high-voltage power lines that transport power from rural and offshore areas to cities and towns. Transmission is key to unlocking clean energy’s potential and ensuring lower energy prices and more reliable power. It also allows a regional grid struggling with extreme weather to import power from neighboring regions. According to a 2021 FERC-NERC report, importing power likely saved the residents of the Midwest and Great Plains from the disastrous consequences suffered by Texans during Winter Storm Uri.
We need to do it all. We need a system that can adapt and respond to whatever is thrown its way, while we move forward with the clean energy transition. In other words, we need to invest in transmission and other grid upgrades while enabling more clean energy to power our homes and businesses.
While states and grid operators have much to do in the short term, the single biggest thing we can do now is pass climate energy legislation under consideration in Congress. It would provide billions of dollars in incentives to transition to clean energy, while ensuring that the lights stay on when we need them most.
With the right investments now, we can build the future we want and need.
Christy Walsh is a senior attorney in the NRDC’s Climate & Clean Energy Program.
Pacific Gas and Electric (NYSE:PCG) has invited 25,000 of its customers who own Tesla (NASDAQ:TSLA) Powerwall batteries to be part of a virtual power plant (VPP) to reward customers financially and support grid reliability in California.
If most of the customers join, the aggregated storage project could eventually form the “world’s largest distributed battery,” generating the output of a small gas-fired power plant, PG&E said in a news release.
About 1,500 customers have signed up so far, and 3,000 have expressed interest, PG&E said.
“Our customers’ home batteries offer a unique resource that can positively contribute to our state’s electric grid and will become more significant as our customers continue to adopt clean energy technology,” Aaron August, PG&E vice president of business development, said in the statement. “In collaborating with Tesla, we are further integrating behind-the-meter battery-based VPPs on the largest scale yet.”
California has experienced energy emergencies during the past two summers and could continue to see shortfalls of more than 1,700 MW over the next four years, according to CAISO and the state’s Public Utilities Commission. The switch to clean energy has made CAISO’s grid especially vulnerable on hot summer nights after solar ramps down and during wildfires that curtail transmission.
To meet its reliability challenges, CAISO has required aging gas plants as small as 27.5 MW to postpone retirement, and state agencies have approved the continued operation of once-through-cooling natural gas plants that harm marine life and had been ordered to close.
FERC and CAISO have made it easier in recent years for distributed energy resources to participate in wholesale electricity markets. DER aggregations are seen as resources that could help offset summer shortfalls in CAISO and other organized markets.
Tesla’s Powerwall batteries manufactured after 2016 have a 13.5-kW capacity, bringing the potential total capacity from all 25,000 PG&E customers to 337.5 MW.
PG&E’s resource portfolio already includes some DER aggregations. As of last year, the utility said its supply included about 150 MW of VPPs used as dispatchable demand response resources, including as part of its Emergency Load Reduction Program. About a dozen aggregators already qualify to participate in PG&E’s Capacity Bidding Program.
The joint effort between PG&E and Tesla could boost such efforts to a new level. Under the program, PG&E will call load-management events, directing participants’ batteries to discharge during high demand from 4 to 9 p.m., May through October. Participating customers will receive a generous $2/kWh.
PG&E residential customers are eligible for the program if they own a Powerwall, have an interconnection agreement with PG&E and are not enrolled in other DR programs. Customers can use a Tesla app to reserve enough backup power to meet their own needs or opt out of an event, PG&E said.
While the U.S. Supreme Court decision in West Virginia v. EPA has been called “devastating” for the agency’s ability to curb carbon emissions from existing power plants, its impact could also place tight constraints on congressional efforts to address major issues such as climate change, a panel of legal experts said last week.
Lisa Heinzerling, Georgetown Law | Georgetown University Climate Center
“The most dangerous point of the court’s decision actually is the court’s seizure of power from Congress, not the agency,” Lisa Heinzerling, a professor at Georgetown University Law Center, said during a webinar hosted by the school’s Climate Center on July 5. “Under the opinion, Congress may no longer enlist agencies’ help in addressing major issues, as it’s done throughout U.S. history, unless it speaks clearly enough for a hostile Supreme Court to hear it. It’s perverse.”
Heinzerling was one of five environmental lawyers on the panel parsing out the details of the decision, the court’s motivations and reasoning, and how environmental and other federal regulations may be able to overcome the obstacles the court’s conservative justices have now put in place.
The 6-3 decision released June 30 ruled that EPA lacks authority to compel generation shifting to reduce carbon emissions, saying the agency failed to provide “clear congressional authorization” for the rulemaking, specifically under the decades-old Clean Air Act. (See Supreme Court Rejects EPA Generation Shifting.)
William W. Buzbee, Georgetown Law | Georgetown University Climate Center
But Heinzerling and other panelists also said the decision will have impacts beyond congressional or EPA efforts to regulate carbon emissions. William W. Buzbee, who also teaches at Georgetown Law, sees the case as “a major arrogation of power by the Supreme Court to itself and the courts, undercutting the power of agencies to do as Congress instructs.”
“This is a terrible problem,” Buzbee said. “The court sort of hamstrings agencies and actually makes it hard for Congress.
“The court repeatedly says Congress had to be more clear and more specific,” he said. “The problem there is that agencies often need flexibility, so you don’t want to have very particularized language. And then second, to pass laws, compromises are often needed, and so sometimes, broader language is a way for Congress to pass laws that are needed.”
Jonathan H. Adler, Case Western | Georgetown University Climate Center
Jonathan H. Adler, director of the Coleman P. Burke Center for Environmental Law at Case Western Reserve University, said the decision sends a message to all federal courts to be “very wary when federal agencies seek to pour new wine out of old bottles. That is to say, when a federal agency takes a statute that may have been last enacted or reauthorized or amended years ago and seeks to use the provisions to address a new or contemporary problem … that has not been addressed before or to do something in a way that has not been done before.”
“This is an enormously important case when it comes to administrative law,” agreed Jeffrey Holmstead, who served at EPA under former President George W. Bush and now leads the Environmental Strategies Group at Bracewell. “In terms of the current debate over climate change, I think it could end up being important for the [Securities and Exchange Commission] in terms of its efforts to mandate additional disclosures regarding greenhouse gas emissions. Maybe it could impact what FERC is trying to do with natural gas pipelines.”
Kirti Datla, director of strategic legal advocacy at Earthjustice, a nonprofit environmental law firm, also sees the decision as having impacts on the regulatory process in general, well beyond EPA. “It’s going to affect everything, from what people ask [an] agency to do in their comment letters, to what agencies think that they can do, to the arguments people will raise when challenging what agencies end up doing,” she said.
The Major Questions Doctrine
At the core of West Virginia v. EPA is Chief Justice John Roberts’s invocation of “the major questions doctrine,” which all the panelists saw as problematic, though for different reasons.
“Precedent teaches that there are ‘extraordinary cases’ in which the ‘history and the breadth of the authority that [the agency] has asserted,’ and the ‘economic and political significance’ of that assertion, provide a ‘reason to hesitate before concluding that Congress’ meant to confer such authority,” Roberts wrote in the decision.
“The agency must point to ‘clear congressional authorization’ for the authority it claims,” Roberts said.
In terms of EPA’s ability to regulate carbon emissions through generation shifting, what this means, Adler said, is that the agency is not losing a power it didn’t exercise; “it’s rather that the court is expressing skepticism that the power ever existed.”
“The court automatically is skeptical of national regulations where agencies address a new problem,” Buzbee agreed. “That’s always the nature of national regulation; agencies step in to address a problem that hasn’t been handled. So, the whole frame of the major questions doctrine is a major problem.”
Kirti Datla, Earthjustice | Georgetown University Climate Center
Datla pointed to Justice Neil Gorsuch’s concurring opinion as potentially layering on even more constraints for regulation, noting that he said the major questions doctrine is important “because it prevents swings in policy” between different administrations.
“The administrative state, in his mind, should be a set of agencies carrying out very limited duties that are so detail oriented that they wouldn’t shift from one president to the next,” Datla said. Justice Elena Kagan’s dissent counters this narrow view as not “what the administrative state currently looks like,” Datla said.
But for Datla, the more pressing problem with the decision is that after setting out the major questions challenge, ‘the majority doesn’t provide any sort of test as to what might be adequate to overcome it. It’s hard to imagine a case where, when this doctrine applies, the agency will be able to overcome the kind of clear statement rule that is being put forth in this case,” she said.
“Congress has two options going forward,” said Heinzerling, who also served at EPA during the Obama administration. “One, it can make major policy decisions itself, or two, it can give clear congressional authorization to an agency to regulate in a particular manner. In fact, I don’t think there’s a real choice.”
The decision “would not allow Congress to pass off a major decision to an agency, even if it really, clearly, in crystal terms passed off that decision to an agency,” she said.
For example, if Congress passed a law specifically authorizing EPA to determine if and how to curb GHG emissions, “I think the court would say that such a statute does clearly authorize EPA to decide a major question,” Heinzerling said. “That would just take the regulatory action out of the statutory frying pan, so to speak, and hurl it into the constitutional fire.”
The Limits of Regulation
Adler sees yet another aspect of the decision’s approach to the major questions doctrine that could have significant impacts on future climate-related litigation. “This concern about showing clear warrant, clear authority in the statute for a major exercise of power is something [Roberts said] the courts should look at upfront” as part of a statutory analysis, he said. “It creates a much broader opportunity for litigants to try and invoke this theory. It gives courts more flexibility in terms of when to consider whether something is a major question.”
Still, Holmstead echoed many other industry analysts who have argued that the decision will have minimal immediate impact on EPA’s ability to regulate carbon emissions under the Clean Air Act. The decision’s rejection of limiting emission reduction regulations to “inside the fence line” of individual generation plants and its seeming endorsement of some form of emissions trading “actually give EPA more flexibility that they thought it had,” he said.
He also said the agency has solid authority to regulate carbon emissions from the transportation sector, provided it sticks with the incremental approach it has adopted in the new standards announced at the end of 2021. (See EPA Rules Will Slash Vehicle Emissions, Rev up EV Market by 2026.)
The challenge ahead for the agency is “if you look at the other industrial sectors,” Holmstead said. “There’s not some way that EPA can gradually shift production of cement or iron and steel to newer, cleaner plants. It’s a technological problem, not a regulatory problem, and I don’t think, beyond the power sector, EPA has really ever developed an effective way to do regulation of industrial sources.
“I don’t think the answer for all of the questions we face with climate change are necessarily regulatory,” he said.
A measure to tax high-income Californians to provide a dedicated funding source for electric vehicle rebates and charging recently qualified for November’s ballot, with most of its financial support coming from ridesharing service Lyft (NASDAQ:LYFT).
Proposition 30, the Clean Cars and Clean Air Act, is intended to reduce greenhouse gas emissions, according to proponents. If passed by voters, the measure would assess a 1.75% tax on individuals and couples with more than $2 million in annual income, raising up to $4 billion a year.
Nearly half the revenues would go toward rebates and incentives for zero-emission vehicle purchases, while 35% would fund ZEV fueling and charging stations. At least half of those funds would benefit low-income households and communities.
The rest would pay for wildfire prevention and suppression. Hiring and training firefighters would take priority.
“To achieve the state’s carbon goals and avoid the worst impacts of climate change, action is needed now regarding two of the largest sources of greenhouse gas emissions in our state: transportation and wildfires,” the measure says.
The California secretary of state’s office reported the initiative had qualified for the ballot June 28, after proponents submitted 720,238 valid signatures, about 100,000 more than required.
Lyft’s involvement has caused some to call the measure a corporate giveaway in disguise. The company has contributed $8 million of the $8.4 million raised so far in support of Prop. 30.
Ridesharing companies in California must “ensure 90% of their vehicle miles are fully electric” by 2030 under the Clean Miles Standard adopted last year by the California Air Resources Board. Drivers for companies such as Lyft and Uber are independent contractors who drive their own vehicles, leaving in question who will pay for their switch to EVs. Prop. 30’s rebates and incentives could help.
Even though the state has dedicated billions of dollars to transportation decarbonization, EV rebates, especially for middle-class drivers, have not been as well funded as advocates think is necessary to meet Gov. Gavin Newsom’s mandate that all new cars sold in-state must be ZEVs by 2035. (See Calif. to Halt Gas-powered Auto Sales by 2035.)
The ballot measure would establish a dedicated revenue stream for rebates, including for Lyft drivers.
“We’re supporting the Clean Cars and Clean Air Act because we’re committed to accelerating the transition to clean vehicles in order to reduce air pollution in California and curb climate change,” Lyft said in a statement. “To meet our state’s bold climate goals, we must do more to help people afford zero-emission vehicles and develop a more robust and convenient charging network.”
Lyft committed in 2020 to reach 100% electric vehicles using its platform by 2030.
“We have no plans to require drivers to switch to EVs,” the company says on its website. “Instead, we believe we can help make driving an EV a profitable choice and are committed to helping drivers transition to these types of cars over time” by expanding its vehicle rental program and promoting cost savings by switching from gasoline-powered cars to EVs.
“Combining lower fuel costs with affordable rental rates, we anticipate that individual drivers can save hundreds of dollars per month, and thousands of dollars per year, on fuel costs alone,” Lyft said.
Earlier this year, environmental, labor and business groups joined together to form Clean Air California, the group backing the measure, to which Lyft contributed.
The Clean Cars and Clean Air Act will “provide consumer subsidies to make electric vehicles more affordable and accessible, particularly to low- and middle-income Californians,” Mary Creasman, CEO of California Environmental Voters, and Joel Barton, secretary-treasurer of the State Association of Electrical Workers, wrote in a joint opinion piece supporting the initiative and touting the formation of Clean Air California.
The initiative would “develop zero-emission vehicle charging infrastructure in residential, commercial and public spaces so that driving a ZEV is as convenient as driving a gas-powered car,” they wrote.
Jon Coupal, president of the Howard Jarvis Taxpayers Association, said revenues for the EV transition should come from the state general fund, which has a record surplus this year, and not from additional taxes. He said he believed the initiative was meant to help ridesharing companies at the expense of taxpayers.
“I think that’s certainly the case,” he said.
Opponents will likely make the corporate-giveaway argument in television ads, which tend to proliferate starting in September, he said. The ballot measure could meet with opposition from voters concerned about raising taxes, even on the wealthy, for fear that they’ll be next, he said.
Progressives “are coming after other revenue sources,” he said. “This Lyft initiative is an example of that.”
Entergy has extended a $588-million settlement offer to regulators in Arkansas, Louisiana and Mississippi over allegations it took advantage of customers through its Grand Gulf Nuclear Station’s energy sales, although some in oversight roles are unhappy with the proposed deal.
The settlement offer stands to resolve more than a dozen FERC dockets filed since 2017 relating to performance and accounting issues at the 1,428-MW Grand Gulf plant in southwestern Mississippi. Entergy said it was making the settlement public as soon as possible because of the dockets involved.
The arrangement would have Entergy admitting no wrongdoing and remitting $235 million to the Mississippi Public Service Commission, $142 million to the Arkansas Public Service Commission, $116 million to the New Orleans City Council, and $95 million to the Louisiana Public Service Commission
The settlement also stipulates that effective July 1, Entergy won’t roll its executives’ bonuses into costs it passes on to customers. Entergy called the proposal a “comprehensive and reasonable effort” to resolve its legal disputes at FERC.
It’s unclear how much of the refunds would ultimately flow to ratepayers. Entergy said it offered the settlement to address uncertainty and further legal expenses.
Grand Gulf station boasts the largest nuclear reactor in the nation. Majority owner and Entergy subsidiary System Energy Resources, Inc. (SERI) sells most of the output at wholesale to Entergy’s Arkansas, Louisiana, Mississippi and New Orleans operating companies.
For years, the Louisiana, Arkansas Public Service Commission and New Orleans regulators have complained about mismanagement and substandard operations at Grand Gulf and sought more than $1 billion in refunds and rate reform for costs passed on to Entergy customers. They said that despite expensive upgrades, the plant has been plagued by frequent outages at customers’ expense. (See Entergy Regulators Ask FERC to Settle Grand Gulf Dispute.)
The regulators also accused Entergy and SERI of massaging accumulated deferred income tax numbers to overcharge customers, overbilling ratepayers for Grand Gulf’s sale-leaseback arrangement, and recovering the costs of lobbying, image advertising and private airplane use in rates through the plant’s sales agreement.
The Nuclear Energy Institute’s data show Grand Gulf is the nation’s worst-performing nuclear plant, with a 66.3% capacity factor from 2018 to 2020. Grand Gulf’s last-place finish is well below the 77.9% capacity factor of Michigan’s Fermi 2, the next least reliable unit in the country.
Mississippi Accepts, NOLA Scoffs
Louisiana’s PSC, which has spearheaded many of the grievances, plans to discuss the settlement offer during its July 27 meeting. The commission doesn’t yet have a stance on the settlement.
“While financial settlements could benefit customers short term, the reason we take on these legal battles at FERC is to ensure that the practices of utilities we regulate are aligned with what is best for their customer’s long term,” Commissioner Craig Greene tweeted Thursday. “I personally want to ensure any settlement, or decision not to settle, focused on that principle.”
In a press release late last month, Entergy said Mississippi regulators have agreed to the settlement. Entergy said $200 million of Mississippi’s refund would offset customers’ high fuel prices from other Entergy generation. It has reserved $35 million for distribution as part of an $80 bill credit per ratepayer.
“By resolving these issues, we can focus on the long-term future of Grand Gulf Nuclear Station to ensure it remains the critical, emissions-free power source it is to serve our customers,” Entergy Mississippi CEO Haley Fisackerly said. “With natural gas prices having tripled over the last year, raising customer power bills as a result, the low-cost power we get from Grand Gulf is a financial lifeline to our customers right now.”
Entergy said it hoped other states involved in the dispute will “follow Mississippi’s lead and seek to settle the remaining claims.” The utility’s other regulators could take the settlement or hold out for larger refunds through the 13 FERC proceedings, many of which the commission has yet to act on.
The New Orleans City Council has not accepted the settlement. In a statement, Council Vice President and Utilities Committee Chair J.P. Morrell said the offer was “deemed well below what the ratepayers were entitled to based upon the council’s litigation posture.”
“This filing was a ridiculous attempt by Entergy to sandbag the city council and mislead the other regulatory agencies in Louisiana and Arkansas into a bad settlement,” Morrell said. “As utility bills continue to spiral out of control in New Orleans, for Entergy and Entergy New Orleans to try to manipulate us into taking less than ratepayers are entitled to is beyond offensive.”
Morell also questioned Entergy’s tactic of publishing the settlement during legal negotiations. He said it gave him “great pause in whether further negotiations are in the public’s best interest.”
In an emailed statement to RTO Insider, the Arkansas commission said it’s currently reviewing Entergy’s offer. It noted that it has until Aug. 1 to file comments on the matter at FERC.
With heat advisories and warnings in place for much of its footprint, SPP set a record for peak load last week.
The grid operator successfully handled demand from a record 51.1 GW of load at 4:30 p.m. CT on July 5, breaking the previous mark of 51 GW set last July. The RTO and its members also maintained reliability last Wednesday and Thursday, when load peaked about 49.9 GW both days.
SPP said a conservative operations advisory issued July 1 alerted its member utilities to operate the regional grid with “extra care” by postponing maintenance on critical facilities and increasing reserve requirements. The advisory was effective Wednesday — the day after the record was set — through last Friday. (See SPP Calls for Conservative Ops This Week.)
“Periods like this week, with extreme heat affecting so much of the country where we operate, underscore how much value there is in regional collaboration,” said Bruce Rew, SPP senior vice president of operations. “We’re proud of the job we do coordinating among our member utilities to keep the lights on.”
SPP highlighted its fuel diversity that is heavy on coal, gas and renewables in helping meet demand fueled by the extreme heat. It said demand response contributed 1.1 MW to the fuel mix.
The RTO kept a resource advisory in place through 10 p.m. Wednesday because of the extreme heat, high regionwide electricity use and uncertainty in SPP’s wind forecast. Neither of the advisories requires consumer conservation.
The Weather Channel says July temperatures are expected to be above average from the Texas Gulf Coast through the Central Plains and into Wyoming.
An RTO spokesperson said it was continuing to watch system conditions during the weekend and into this week, as it will do as the summer progresses.
SPP members serve about 18 million people in the grid operator’s 14-state region, which covers 550,000 square miles.
Solar farms are set to proliferate in a sun-soaked county in central Washington.
In May, a Yakima County Planning Division hearing examiner approved a conditional use permit for the 94-MW Black Rock Solar project, which will be able to power about 20,000 homes at full output.
Construction of the project is expected to begin in the first half of 2023 and be completed in mid- to late 2024, Brandon Reinhardt, development director for BayWa r.e. Americas said in an interview. Reinhardt declined to discuss the project’s budget.
The project is targeted for roughly 1,000 acres in eastern Yakima County, an area that has been attracting several solar ventures. BayWa plans to lease the land from a farmer, and the project’s solar panels will co-mingle with sheep that graze on the grass on the site. That would make the project Washington’s second agrivoltaic site, in which panels are located among crops and lands dedicated to grazing livestock.
The state’s first agrivoltaic projectis scheduled to go online this month on the Colville Indian Reservation north of the Grand Coulee Dam. Two geodesic domes filled with various crops will be located adjacent to solar panels used to power the domes’ heat and water as well as some nearby homes.
At least four solar projects have targeted eastern Yakima County, a dry shrub-steppe area. “It’s essentially the strength of the sunshine,” Reinhardt said.
In December, Gov. Jay Inslee approved the 80-MW Goose Prairie project on 625 acres in eastern Yakima County at the recommendation of the state’s Energy Facilities Siting Evaluation Council (EFSEC).
Two more projects are going through reviews by EFSEC. In April, Cypress Creek Renewables applied to EFSEC for permission to build two 80-MW solar farms — High Top Solar and Ostra Solar — in the same eastern Yakima County region.
In Washington, solar and wind developers have the option of choosing to handle project permitting through either EFSEC or the appropriate county government.
While three of the projects chose the EFSEC route, BayWa wanted to work with the Yakima County government. “We had a supportive county staff. We didn’t feel much in the way of opposition,” Reinhardt said.
MISO stakeholders say the grid operator’s plan to fold a stakeholder group dedicated to loss-of-load estimates into its resource adequacy subcommittee by year’s end will result in papering over a full risk picture.
They said there’s good reason to keep the Loss of Load Expectation Working Group (LOLEWG) because it helps shape the annual LOLE study and the Resource Adequacy Subcommittee (RASC) reviews the results with little opportunity for stakeholder input.
Travis Stewart, representing the Coalition of Midwest Power Producers, said LOLE discussions are “proactive” in the working group and “reactive” in the subcommittee.
“The intention is not to decrease transparency, but this move certainly will,” Stewart said. “Stakeholders are not asking for a yeoman’s work here. We’re really just asking for three to four meetings per year.”
Lynn Hecker, MISO’s senior manager of resource adequacy policy, said there’s substantial overlap of LOLE issues between both groups. She said MISO would be more efficient if it retires the LOLEWG by the end of the year and rolls discussion into RASC meetings, adding that staff already double-posts its study progress to both groups. (See MISO Moves to Disband Stakeholder Loss of Load Group.)
“This is not intended to reduce transparency or discussion by any means,” Hecker told the working group during a teleconference Thursday. She said MISO could schedule additional workshops to tackle the LOLE study’s more technical aspects.
Multiple stakeholders asked that MISO host the LOLEWG for at least another year.
Xcel Energy’s Kari Hassler pointed out that the RTO has already cut the number of RASC meetings from 12 to eight each year and that the meetings frequently run over agenda timeslots. She said she didn’t see how the RASC could take on another working group’s tasks.
“It seems like we have a lot of LOLE issues to address if the [seasonal auction and accreditation] is approved,” she said. “I very much want to maintain the LOLE working group.”
Hecker said staff will collect more stakeholder feedback on retiring the working group over the next two weeks and factor that into a final decision.
The grid operator is morphing its LOLE study into a seasonal calculation that includes four separate planning reserve margin requirements. It’s adding seasonal inputs to its LOLE model for the 2023/24 planning year, assuming FERC approval of seasonal capacity auction and resource-accreditation design proposals.
MISO resource adequacy engineer Darius Monson said staff will now calculate additional cold-weather outages by adding a forced outage adder for extremely cold temperatures. Previous LOLE estimates didn’t include extra generation outages brought on by plummeting temperatures, leading to an undercount of generation outages.
Some stakeholders said it’s still unclear how MISO will crunch LOL estimates to wind up with four separate planning reserve margin requirements.
With its recent capacity auction shortfall, MISO has an annual value of a one-day-in-5.6 years loss-of-load risk instead of its one-day-in-10 years target.
