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July 6, 2024

SCE Sees Wildfire Risk Decline as Load Outlook Improves

Independent measures show Southern California Edison has sharply reduced its financial risk from catastrophic wildfires compared with pre-2018 levels, Pedro Pizarro, CEO of SCE parent Edison International, said during a Feb. 22 earnings call. 

The utility exceeded its own targets for hardening its system against fire risk last year when it installed 1,100 circuit miles of covered conductor across its distribution system, raising the total to 5,850 miles installed over the past five years.  

“We are proud of this progress, which, combined with enhanced vegetation management, asset inspections and other programs, has significantly reduced the need for public safety power shutoffs,” Pizarro said, referring to the fact that the physical measures have meant power shutoffs now account for just 10% of SCE’s fire avoidance, compared with 100% five years ago. 

On the heels of those developments, SCE last year showed an 85 to 88% reduction in its wildfire-related risks compared with pre-2018 levels based on an independent risk model managed by Moody’s RMS, he said. 

The utility in 2023 saw no fire ignitions due to the failure of covered conductor. Last year also marked the fifth straight year with no catastrophic wildfires in its service territory, according to a presentation shown during the call. 

The presentation also noted that SCE expects to have hardened 90% of its distribution lines in high-fire-threat areas (HFRAs) by the end of 2025, prompting one analyst on the call to ask whether the company is preparing to address new areas that emerge as high-risk in the future due to changing climate conditions. 

“Clearly, we continue to monitor how the landscape is changing,” Pizarro said. “We do that in partnership with fire agencies, with [California Office of Energy Infrastructure Safety], so to the extent that additional areas are designated HFRA, high-fire-risk areas, in the future, then we would make sure that we’re using the same standards that we use for high-fire-risk areas today.” 

Electrification to Boost Load, Reduce Energy Costs

Edison expects a significant boost from California’s push to decarbonize its economy, an outlook shared by its neighbor to the north, Pacific Gas and Electric. (See PG&E Foresees Strong Growth from Electrification, Data Centers.) 

“After years of flat demand, SCE is projecting an uptick in electricity usage of about 2% annually over the coming years,” Pizarro said, in line with PG&E’s forecast load growth of 1 to 3% through 2028. 

“As more and more vehicles and buildings are electrified, the electricity demand will increase by 80% over the next 20 years, which will benefit customer affordability through a 40% decrease in their total energy costs across electricity, gasoline, and natural gas,” he said. 

Pizarro said the expansion of high-voltage transmission and local distribution networks will be “critical” to California meeting its climate goals. Edison estimates a 6 to 8% compound annual growth rate in its rate base over the next five years, from $43 billion this year to $55.2 billion in 2028. That growth will be “driven by wildfire mitigation and important grid work to support California’s leading role in clean energy transition,” the company said in its presentation. 

The company also foresees the opportunity to expand its rate base by an additional $2 billion through investments in a “next-generation” enterprise resource planning system, advanced metering infrastructure, and grid reliability and resilience upgrades, as well as another $2 billion in transmission projects subject to FERC approval. 

In January, the California Public Utilities Commission rejected SCE’s 2021 proposal to spend $744 million to install new heat pumps in 250,000 homes in its territory and assist lower-income households with necessary electrical upgrades. The regulator expressed concern about spreading the costs for the program across the utility’s customer base at a time of already high energy costs.   

“A substantial amount of federal, state and ratepayer money is already being spent, and has been allocated for future use, to largely implement the same building electrification efforts in SCE’s proposal,” the commission said in its decision (A2112009). 

“Although the CPUC denied SCE’s building electrification application due to their near-term affordability pressures, it acknowledged SCE’s leadership in proposing programs to accelerate much-needed building decarbonization,” Pizarro said. “The utility will continue to evaluate the results of other building electrification pilots it has in progress and look for different ways to support the state in advancing its clean energy priorities.” 

Edison reported 2023 profits of $1.197 billion ($3.12/share), compared with $612 million ($1.61/share) in 2022. Fourth-quarter earnings came in at $378 million ($0.99/share), compared with $415 million ($1.09/share) a year earlier. 

PG&E Foresees Strong Growth from Electrification, Data Centers

California’s “leadership in electrification” will be a key driver of Pacific Gas and Electric’s expected customer growth in the coming years, CEO Patti Poppe said Feb. 22 during the utility’s fourth-quarter and year-end earnings call. 

PG&E is forecasting annual load growth of 1 to 3% through 2028, based in large part on expectations for increased electrification and continuing uptake of electric vehicles among its customers, according to slides accompanying the call. 

The utility also foresees strong growth in demand from commercial customers, with service applications from new data centers increasing threefold last year over the previous four years. 

“As we look at the five-year forward load-growth forecasts, the back end of that forecast will reflect the additional data center demand,” Poppe said. “And look, I think we all can agree that the only thing that’s happening with data centers is they need more of them.” 

PG&E estimates $62 billion in capital expenditures over 2024-2028, with the spending supporting “strategic capital investments in electrification, energization, undergrounding and wildfire mitigation,” according to a footnote in the slides. That represents a 20% increase over the utility’s outlook for the 2023-2027 period and translates into a 9.5% compound annual growth rate (CAGR) for its rate base. 

The company also foresees opportunities for an additional $5 billion in spending over the next five years on transportation electrification infrastructure, transmission upgrades, incremental business connections, hydroelectric facilities and storage, and information technology and automation. 

Despite the anticipated sharp growth in spending, Poppe said the company expects to hold customer rate increases to 2 to 4% annually based on new cost-saving measures and the ability to spread costs over the growing load base. 

Poppe attributed the cost-saving to the utility’s adoption of a “lean operating system,” which last year drove a 5.5% reduction in nonfuel operations and maintenance costs after a 10% CAGR in those expenses during the previous five years. 

“As a reminder, several years of doing whatever was necessary to respond to back-to-back crises pushed our capital-to-expense ratio far below the industry average,” she said. “This is where we have a wealth of opportunity and a long runway to drive efficiencies with sustainable savings benefiting both our customers and our investors.” 

Poppe also touted PG&E’s improving record related to wildfire ignitions. 

The utility has been found responsible for its equipment sparking some of the most destructive fires in California’s history, including the deadly 2018 Camp Fire, which burned down most of the rural town of Paradise and killed 85 people. (See Cal Fire Pins Deadly Camp Fire on PGE.) 

PG&E started no “catastrophic” fires in its service territory last year, while tallying 68 reportable ignitions, compared with 91 in 2022, 134 in 2021 and 201 in 2017. Based on the scoring methodology established by the California Public Utilities Commission, the utility’s wildfire risk fell by 94%. 

“While we’re extremely pleased with these results, our team certainly isn’t stopping here. We see further opportunities to drive overall wildfire risk reduction beyond the 94% achieved in 2023 as we continue with additional system hardening and deployment of new technologies,” Poppe said. 

PG&E last year undergrounded 364 miles of distribution lines at a cost of just under $3 million per mile, bettering targets of 350 miles at $3.3 million per mile. Poppe said the work will help prevent public safety power shutoffs and other outages for 15,000 customers in areas of high fire risk. 

The utility expects to underground around 250 miles of lines this year, part of a plan to bury 10,000 miles of lines — or about 8% of its distribution system, Poppe noted. 

Pacific Generation a ‘Great Transaction’

PG&E is still awaiting the CPUC’s decision on the proposed spinoff and sale of a minority stake in Pacific Generation, a standalone subsidiary that would control 5.6 GW of generating capacity, including more than 1.3 GW of battery and pumped storage. FERC last year approved the plan, which would raise an estimated $3.4 billion for PG&E. (See FERC Approves PG&E’s Proposal to Spin off Generation.) 

“We think this a great transaction for customers,” PG&E CFO Carolyn Burke said, adding that the advantageous financing costs stemming from the spinoff will also improve the utility’s balance sheet and lower overall costs for utility customers. 

Both Burke and Poppe emphasized during the call that PG&E would not be seeking to raise money from equity markets this year because the company’s current stock price makes other financing options more “favorable.” 

PG&E reported earnings sat at the top end of previous estimates. The company made $2.242 billion last year ($1.05/share), compared with $1.8 billion ($0.85/share) in 2022. Fourth-quarter earnings per share jumped to 84 cents from 24 cents a year earlier. 

Dominion Sells 50% of Coastal Virginia Offshore Wind to Stonepeak

Dominion Energy on Feb. 22 reported earnings of $2 billion in 2023 and announced that it has closed on an equity partner for its Coastal Virginia Offshore Wind (CVOW) project. 

The utility is selling a 50% noncontrolling interest in CVOW to Stonepeak through the formation of a new public utility subsidiary, under Virginia’s jurisdiction, that will own the project, while Dominion will continue to construct and eventually operate the wind farm on its own. 

“The Coastal Virginia Offshore Wind project continues to proceed on time and on budget and consistent with our previously communicated timing and cost expectations,” CEO Robert Blue said. “A competitive partnership process attracted high-quality interest, resulting in a compelling partner for CVOW. Stonepeak is one of the world’s largest infrastructure investors, with more than $61 billion in assets under management and an extensive track record of investment in large and complex energy infrastructure projects, including offshore wind. Their significant financial participation will benefit both our project and our customers.” 

The deal includes a number of provisions in which Stonepeak would share in any cost overruns, but Blue told investors on a conference call that he expects Dominion will complete CVOW on time and on budget. 

“We’ve been very clear with our team, and with our suppliers and partners, that delivery of an on-budget project is the expectation,” Blue said. 

Dominion posted a video highlighting the work it and suppliers have done on the project so far, with some monopiles being delivered to Virginia while construction continues on other components elsewhere, he added. 

The company has already invested $3 billion in the project, and it plans to put in another $3 billion before the end of the year. A little more than 92% of the project’s costs are now fixed, and the firm expects its final cost will be $9.8 billion. 

Stonepeak will pay Dominion about $2.9 billion once the deal closes to cover its pro rata share of investments so far, but the deal will have it invest about $4.9 billion assuming the cost is on budget. The investment firm could be on the hook for more, but its pro rata share of costs goes down the more costs overrun Dominion’s estimates, while the utility would wind up with a greater share of CVOW if costs are higher than expected. 

The deal has to get approval from the Virginia State Corporation Commission (SCC) and the North Carolina Utilities Commission. 

“It will be a public utility in Virginia and be entitled to recover its prudently incurred costs of constructing and operating the project under the existing offshore wind rider in Virginia,” Blue said. 

While last year Dominion was focused on getting a bill through the legislature that changed how Virginia regulates its business, this legislative session has been slow when it comes to electric power issues, Blue said. One exception was the legislature finally naming two new members to the SCC, which had been short staffed for years. (See Virginia State Corporation Commission Finally Gets All Seats Filled.) 

“They have extensive experience in both government and the private sector,” Blue said. “And we look forward to working cooperatively with these well qualified new members.” 

Dominion is going to be back before its investors shortly, with an investors day scheduled for March 1, at which it will present a “comprehensive strategic and financial update” and conclude the business review it has been working on for months. 

Avangrid Avoids Major Offshore Wind Losses

Avangrid reported a year-over-year decrease in income but said a timely pause in its offshore wind projects saved it from write-offs that could have run into the billions. 

CEO Pedro Azagra gave an upbeat fourth-quarter and year-end assessment to financial analysts Feb. 22, noting significant progress on the long-delayed New England Clean Energy Connect transmission line and landmark achievements with Vineyard Wind 1, both now under construction. 

In 2022, Avangrid was one of the first developers to publicly sound the alarm about the financial crisis facing the nascent U.S. offshore wind industry, as projects that had locked in power purchase agreements years earlier saw their projected costs of construction soar.  

Developers holding contracts for more than half the contracted U.S. offshore wind capacity have canceled the contracts or the projects. 

In 2023, Avangrid agreed to $64 million in penalties to cancel its power purchase agreements for Park City Wind in Connecticut and Commonwealth Wind in Massachusetts. After taxes, the net cost was just $29 million, Azagra said.  

(See Park City Wind to Cancel PPAs, Exit OSW Pipeline and Commonwealth Wind PPA Cancellations OK’d.) 

By contrast, some other companies developing projects off the Northeast coast — BP, Equinor, Eversource and Ørsted — recently have reported huge impairments. 

“This allows us to maintain future profitable opportunities with this business,” Azagra said, “as opposed to our peers’ multibillion-dollar write-offs, which continue to mount.” 

Vineyard Wind 1, the nation’s first large-scale offshore wind project, was far enough along when supply chain constraints and cost increases hit the industry that it could continue to construction. (South Fork Wind, about one-sixth the size of Vineyard, also started construction around the same time and is nearing completion.) 

Avangrid and the state of Massachusetts chose Feb. 22 to celebrate the fact that five of Vineyard’s turbines are spinning at full capacity, delivering up to 68 MW of emissions-free electricity to Massachusetts. Five more are in place but not operational. 

That leaves 52 turbines and 738 MW to go, more than one year after construction started on Vineyard and nearly three years after federal regulators greenlighted the project.  

Azagra sidestepped an analyst’s question on when the 50-50 joint venture with Copenhagen Infrastructure Partners would reach full operation. 

“What we have learned in the last 12 months is a focus sometimes on specific deadlines is almost irrelevant,” he said. “The important thing is to finish the project.” 

In other news, Avangrid Networks President Catherine Stempien said construction of New England Clean Energy Connect in Maine is going well after litigation delays. (See New England Clean Energy Connect Wins Court Battle.) 

“Twenty-five percent of our foundations have been set and 20% of poles,” she said. “We’ve already started stringing conductor on the corridor. We’ve also been doing substantial construction laying the foundation for our HVDC converter station.” 

The line will bring 1,200 MW of power from Québec hydroelectric facilities to New England. 

Avangrid also continues selective onshore renewable development, Azagra said. It commissioned 311 MW of onshore capacity in 2023 and is working on projects totaling 998 MW, 687 MW of which is contracted to power data centers. 

Avangrid reported GAAP net income of $397 million for the fourth quarter of 2023 and $786 million for the full year. That compares with $147 million and $881 million, respectively, in 2022. 

GAAP earnings per share were $1.03 in the fourth quarter of 2023 and $2.03 for the full year, compared with $0.38 and $2.28, respectively, in 2022. 

Avangrid’s stock closed 0.3% lower Thursday amid average trading volume. 

MISO Publishes Call to Action to Bypass Danger in Reliability Imperative Report

MISO has released a new edition of its Reliability Imperative report, with the latest version containing an urgent call to action for all MISO players.

“We have to face some hard realities,” MISO CEO John Bear prefaced the refreshed report. “There are immediate and serious challenges to the reliability of our region’s electric grid, and the entire industry — utilities, states and MISO — must work together and move faster to address them.”

The report emphasized that all three must coordinate at once to avoid a “looming mismatch” between retiring baseload generation and an influx of weather-dependent generation. MISO said members should temper retirements to retain some dispatchable “transition resources” as “reliability insurance.” 

MISO first published its Reliability Imperative report in 2020 and has updated it periodically since. It describes the RTO’s risk profile and the steps MISO, members and state regulators should take to mitigate threats. 

In a Feb. 21 press release accompanying the report, MISO said that in addition to “significant changes to the generation fleet, the electric power industry is facing an increase in extreme weather events, large load additions, electrification, supply chain issues, permitting delays and fuel assurance issues.”

Members have cut carbon emissions by about 30% since 2005, and Bear said the footprint could cut them by more than 90% in coming years. 

“Studies conducted by MISO and other entities indicate it is possible to reliably operate an electric system that has far fewer conventional power plants and far more zero-carbon resources than we have today. However, the transition that is underway to get to a decarbonized end state is posing material, adverse challenges to electric reliability,” Bear warned. He said that until new technologies become viable, MISO will continue to need dispatchable resources.  

“We’re seeing traditional generators being replaced by resources that aim to meet clean energy goals but that do not have the same reliability attributes as those they are replacing,” Bear said.  

MISO said supply chain and siting and permitting issues outside of MISO’s control are hampering new generation projects that will be crucial to reliability. The grid operator also said the footprint is increasingly housing single-site, large load additions like data centers that planned and existing generation might not be able to accommodate, especially when considering new pressure on the grid from electric vehicles and other electrification. 

MISO reported that its South region is experiencing an industrial renaissance and soon could add manufacturing plants producing steel, hydrogen, liquefied natural gas and other heavy industry totaling 1 GW in new demand. 

MISO said diminishing generation and load growth over the past decade-plus already have depleted its surplus reserves.

“Since 2022, MISO has been operating near the level of minimum reserve margin requirements,” it said. 

The RTO said ongoing initiatives into 2024 like applying a sloped demand curve in capacity auctions, introducing a capacity accreditation that’s more reflective of actual generator availability and planning a second long-range transmission portfolio should help the footprint make progress toward a more reliable transition.  

MISO President Clair Moeller said MISO sees “very little risk of overbuilding the transmission system; the real risk is in a scenario where we have underbuilt the system.” 

FERC Catches Ketchup Caddy Co. in Another Fake DR Scheme in MISO

FERC is poised to levy $27 million in penalties on a Texas-based LLC meant to sell in-car ketchup holders that collected more than $1 million in undeserved MISO demand response payments.  

The commission issued a show-cause order Feb. 21 to Ketchup Caddy LLC and CEO and owner Philip Mango, indicating it will assess $25 million in civil penalties on Ketchup Caddy, $1.5 million in civil penalties on Mango and order Mango to disgorge $506,502, plus interest, in unjust profits for bogus load reductions unless he can offer an explanation (IN23-14).  

Philip Mango | Jen Mango

FERC’s Office of Enforcement concluded that Ketchup Caddy is a “fraudulent enterprise with no legitimate market activity, registering and clearing demand response resources without their knowledge or consent and collecting capacity payments in turn, without making payments to the registered resources.” Enforcement staff said Mango “made no attempt to contract with — or even to contact — legitimate customers, and the purported customers Ketchup Caddy registered with MISO would not have responded if dispatched.”  

According to enforcement staff, Ketchup Caddy, Mango and co-founder Todd Meinershagen collected more than $1 million in fraudulent capacity payments beginning with the 2019/20 MISO capacity auction. In doing so, the company denied other MISO suppliers the opportunity to earn more than $17.6 million because its fraudulent offers suppressed capacity prices in the 2019/20, 2020/21 and 2021/22 MISO Planning Resource Auctions. The company received weekly capacity payments until October 2021, when MISO became aware of the scheme and removed Ketchup Caddy from its capacity market.  

Mango admitted to having no intention of enrolling actual customers, FERC staff said, and neither he nor Meinershagen attempted to defend their actions.  

Meinershagen already agreed to pay more than $525,000, including interest, for his role in the market manipulation as part of a December 2022 settlement agreement.  

Meinershagen, a computer programmer, reportedly used a random number generator on an Ameren website to land on actual customer accounts and “scrape” customer data. Staff said it was Mango’s responsibility to contact customers and convince them to participate in a demand response program with zero payout to them and 100% going to Ketchup Caddy. Mango said he never contacted potential demand response customers and never attempted to draft contracts because there was no way customers were going to agree to accept nothing. By early 2019, he had run out of time and fraudulently registered unwitting customers.  

“We were accepted in late February and had 48 hours to load customers into the MISO program before it closed,” Mango said of his experience registering demand response with MISO.  

FERC staff said Ketchup Caddy cleared 211.1 MW in the 2019/20 MISO capacity auction, 303.2 MW in the 2020/21 auction and 372.3 MW in the 2021/22 auction. The commission said Ketchup Caddy’s false registrations and offers went under the radar because MISO didn’t order curtailment in any of those planning years and only required “mock tests to verify performance.”  

Mango said he was looking for “essentially free money, no harm to the customer” and told staff that he planned to“[d]o this for just a couple of years, make a bunch of money to put kids through school and do all those things, and no one’s hurt. Do it with the least amount of resource possible, the least amount of money invested.” 

Mango reportedly admitted that his company didn’t provide any value to the MISO market and any “reasonable person” would conclude that his actions were illegal. Mango also said he kept Meinershagen in the dark” and created a “mirage” to make him believe that Ketchup Caddy was legitimate.  

“Upon further reflection, I realize the egregiousness and the error of my ways,” he told FERC staff.  

Ketchup Caddy’s LinkedIn page routes to a distributor page for Plexus, a multilevel marketing company that deals in dietary supplements. MISO recognized Ketchup Caddy as a market participant in late 2018. The Frisco, Texas-based company was originally created by Mango to sell an in-car ketchup holder he invented.  

FERC gave Mango 30 days to respond to its order. Mango can choose between a prompt penalty assessment, or he can plead his case at an administrative hearing before an administrative law judge.  

This is the third time companies have been caught manipulating MISO’s demand response program and collecting unjustified payments, with penalties set to reach several million dollars.  

In January, FERC’s Office of Enforcement found that an air separation facility in Indiana accepted payments for phantom load reductions. It ordered Northern Indiana Public Service Co. and the U.S. arm of U.K.-based chemical company Linde Inc. to pay $66.7 million to settle charges it gamed MISO’s demand response program. In that case, FERC found that Linde’s Calumet Area Pipeline Operations Center in northwest Indiana would operate some equipment in the facility needlessly and vent gases it distilled back into the atmosphere, solely for the purposes of raising its registered baseline electricity use with MISO. (See FERC Orders $66.7M in Penalties and Disgorgement on Linde and NIPSCO.)  

Last year, FERC ordered an Arkansas steel mill and Entergy Arkansas to return a $35 million settlement for the steel mill’s yearslong failure to reduce electricity use as a demand response resource. Soon after, MISO’s Independent Market Monitor recommended the RTO implement demand response offer floors and attestations of expected levels of energy consumption to ward off similar DR schemes in the future. (See IMM Presses MISO for New Rules After DR Market Gaming.)  

Prices, Renewables Rise in New England Capacity Auction

[Editor’s Note: This story was updated to correct some details of the capacity awards.]

ISO-NE’s capacity market continued its rollercoaster ride as prices for Forward Capacity Auction 18 rose to $3.58/kW-month, a nearly $1 increase (38%) over last year and the second highest “Rest-of-Pool” price since FCA 13. 

The RTO, which completed the auction after four rounds of bidding on Feb. 5, filed its results for FERC approval Feb. 21 (ER24-1290). The RTO asked FERC to set a deadline of April 8 for comments.  

The auction for the June 1, 2027-May 31, 2028, delivery year procured 31,556 MW of capacity — slightly above the 30,550-MW net installed capacity requirement (ICR) — from about 950 resource obligations, ranging from 7 kW (Sunnybrook Hydro 2) to the Seabrook and Millstone Point Unit 3 nuclear plants at 1.2 GW each. The capacity will cost ratepayers about $1.3 billion. 

Last year, prices cleared at $2.59/kW-month in all zones and import interfaces except for the New Brunswick interface, which cleared at $2.551. (See FCA 17 Shows Clean Energy Boost, Endgame for Coal in New England.) 

ISO-NE’s calculation of the quantity of capacity procured is based on the amounts for June 2027. Among fuel types, natural gas led with 13,817 MW (44% of the total), followed by fuel oil and nuclear at 11% each, and hydropower at 10%.

Demand response contributed 2,614 MW (8%), followed by electricity used for energy storage (5.8%)

Solar (2.2%) and wind (1.7%) trailed kerosene at 3%, although their combined total of 3.9% was up from about 3% in last year’s auction.

Imports contributed 1.5%.

New resources represented 1,484 MW, 4.7% of the total, including 741 MW of storage, 185 MW of wind and almost 53 MW of solar.

In total, the RTO said, emissions-free renewable generation, storage and demand resources contributed about 40% of the total at almost 1,085 MW. 

ISO-NE capacity demand curve, net installed capacity requirement (net ICR) and net cost of new entry (net CONE) for Forward Capacity Auction 18 | ISO-NE

Zones

The auction set separate zones for Northern New England (New Hampshire, Vermont and Maine load zones), Maine (modeled as a nested export-constrained zone within NNE), and the Rest-of-Pool. 

The ROP included Southeastern Massachusetts, Rhode Island, Northeastern Massachusetts/Boston, Connecticut and Western/Central Massachusetts.  

The descending clock auction started in each zone at $14.525/kW-month, resulting in a clearing price of $3.58/kW-month for all zones and imports over the New York AC ties (122.89 MW), New Brunswick external interface (70 MW), Hydro-Québec Highgate external interface (18.17 MW) and the Phase I/II HQ Excess external interface (253.78 MW). 

There were no active demand bids for the substitution auction and the RTO did not reject any retirement delist bids for reliability reasons.

Supreme Court Skeptical of EPA’s Good Neighbor Plan

The U.S. Supreme Court’s conservative majority on Feb. 21 appeared inclined to pause the Biden administration’s Good Neighbor Plan, an EPA rule to limit ozone-forming nitrogen oxide emissions from power plants and industrial facilities in certain states. 

The plan was first proposed in 2022, and EPA issued a final rule early last year that applied to 23 states found to be contributing to unhealthy levels of ground-level ozone in neighboring downwind states, making it difficult for those states to meet the 2015 National Ambient Air Quality Standards. 

Lower courts have stayed the rule in 12 states while they consider it, but the agency has continued to enforce it for the remaining 11. The Supreme Court agreed in December to listen to petitions for an emergency stay — consolidating challenges by Ohio, Indiana and West Virginia with those of Kinder Morgan, the American Forest and Paper Association, and U.S. Steel — after the D.C. Circuit Court of Appeals declined to rule on the matter while the lower court challenges proceed. Ohio and Indiana are among the remaining 11 states, while West Virginia is not currently required to comply. 

Several conservative justices focused on whether the plan’s cost calculations are still justified for the remaining states, while liberal justices expressed concern about the precedent the court would set by ruling before the lower courts had a chance to hear the case. 

Representing the states, Ohio Deputy Solicitor General Mathura Sridharan asked the court to pause the implementation of the rule, arguing that “while these [lower court] proceedings are going on, the states and their industries continue to suffer irreparable harm.” An emergency ruling is justified by “the threat of power shortages and heating shortages.” 

EPA’s calculation of the compliance cost threshold was set based on all 23 states, and the agency did not adequately consider how removing states from the plan would affect it, said Catherine Stetson, representing the industry challengers. 

“What happens if you take out the states where maybe you can control those costs most cheaply and you’re left with states that actually have much higher cost thresholds to impose on industries or on” electric generating units? Stetson asked. 

Justice Brett Kavanaugh said the burden is on EPA to show the cost threshold calculated based off all 23 states should still apply to a smaller number of states.  

“The problem is we’re not sure if the requirements would be the same with 11 states as with 23,” Kavanaugh said. “It’s just not explained.” 

But other justices expressed skepticism that a stay in some states justified a re-evaluation for the others, as the compliance costs are fixed and not changed by the exits. 

“If all these lawsuits that the states are bringing are going to end up losing,” said Justice Elena Kagan, “the idea that you can be here and be demanding emergency relief just because states have kicked up a lot of dust seems not the right answer to me.” 

Justice Amy Coney Barrett questioned Stetson on the timing of challengers’ request for the Supreme Court to intervene. 

“You’ve talked about projected injury, projected costs that you’re going to incur, but, presumably, I mean, the rule’s been in effect for a while,” Barrett said. “Why haven’t you talked about that? I think you’re kind of shifting gears now.” 

Stetson responded that EPA’s plan will cause significant costs to power plants over the coming 12 to 18 months, triggering “immediate reliability issues.” 

Justice Ketanji Brown Jackson said she is concerned about the precedent the Supreme Court would set by pre-empting a ruling from the D.C. Circuit. 

“Your argument is just boiling down to, ‘We think we have a meritorious claim, and we don’t want to have to follow the law while we’re challenging it,’” Jackson said. “I don’t understand why every single person who is challenging a rule doesn’t have that same set of circumstances.” 

Representing EPA, Deputy U.S. Solicitor General Malcolm Stewart argued that the court must consider harms that pausing the agency’s plan would have on downwind communities. 

“To stay the rule in its entirety based on some theoretical possibility that the contours of an 11-state rule might have been somewhat different if EPA had anticipated all the stays would be terribly unfair to the downwind states,” Stewart said. 

The agency has said the plan “will save thousands of lives and result in cleaner air and better health for millions of people living in downwind communities.” 

The final rule noted that ozone exposure increases risks of early death, exacerbates asthma symptoms and harms ecosystems. EPA also highlighted environmental justice benefits of ozone pollution reductions, noting that the agency’s impact analysis “found greater representation of minority populations in areas with poor air quality relative to the revised ozone standard than in the U.S. as a whole.” 

“The harms from a stay will flow to both the residents of downwind states who will experience health dangers and to downwind industry, which pays increased costs to compensate for upwind pollution and comply with the current, more stringent standard,” New York Deputy Solicitor General Judith Vale said, representing states in support of the rule. 

Vale argued that the costs of pausing the rule would be greater to downwind states than the costs the rule would impose on upwind states, noting that the rule requires “controls that downwind sources and many other sources across the country have already done, … like turning on pollution controls on power plants that are already installed.” 

Kavanaugh said both sides have shown evidence for harm, and therefore the “only other factor on which we can decide this under our traditional standard is likelihood of success on the merits.” 

When considering the merits, Kavanaugh said the court must evaluate whether EPA’s methodology was arbitrary and capricious. 

“One of the classic arbitrary and capricious conclusions is a failure to explain,” Kavanaugh said. “One of the complaints they have, which we have to evaluate, is whether they’re likely to succeed in saying that the rule was not adequately explained.”

Nevada Draft Climate Plan Outlines GHG-reduction Priorities

Nevada has released a draft climate action plan that lays out steps the state can take quickly to move toward greenhouse gas reduction goals. 

The Nevada Division of Environmental Protection (NDEP) received a $3 million federal grant to develop the strategy, known as the Priority Climate Action Plan (PCAP). NDEP released a draft PCAP on Feb. 15; public comments will be accepted through Feb. 22. 

The plan lists a wide array of priority actions grouped into six focus areas. Among priority actions within the transportation focus area are incentives to electrify government and large commercial vehicle fleets, and rebates for the purchase of zero-emission vehicles (ZEVs) or electric bikes. 

Developing infrastructure for medium- and heavy-duty ZEVs is another priority, as is updating and expanding the state’s EV charging plan under the National Electric Vehicle Infrastructure (NEVI) program. 

Under the energy system focus area, the plan proposes incentives such as grants for developing clean energy hubs at former mining sites or brownfields. 

In addition to transportation and energy systems, the plan’s other four focus areas are buildings, industry, waste reduction, and landscape restoration and carbon sequestration. 

“The primary objective is to identify near-term, high-priority, implementation-ready measures to reduce GHG emissions,” the plan states. 

Implementation Grants

The PCAP is just the first phase of planning funded by the $3 million federal grant. The funding, from EPA’s Climate Pollution Reduction Grant (CPRG) program, will also cover NDEP’s development of a more in-depth Comprehensive Climate Action Plan (CCAP). 

In addition to money for planning, the CPRG will offer $4.6 billion for implementation of GHG-reduction measures included in a PCAP. States have a March 1 deadline for submitting a PCAP; applications for implementation grants are due April 1. 

Nevada set greenhouse gas reduction targets through Senate Bill 254 in 2019. The state is aiming for a 28% reduction in GHG emissions by 2025 relative to 2005 levels; a 45% reduction by 2030; and zero or near-zero emissions by 2050. 

But Nevada’s 2023 Greenhouse Gas Inventory has projected that GHG emissions will fall short of the reduction targets, with a 24.5% reduction in 2025 and a 27.8% reduction in 2030. 

The PCAP projects a 48.2% reduction in 2050. 

By implementing measures in the PCAP, Nevada could meet the 2025 and 2030 targets but would still come up short of the 2050 goal, the plan said. 

“Meeting 2050 goals will require additional measures, to be described in the CCAP,” the draft plan said. 

NDEP’s release of the draft PCAP comes after Gov. Joe Lombardo (R) last year ordered an overhaul of Nevada’s 2020 climate strategy to reflect his energy policies. Lombardo defeated the incumbent governor, Democrat Steve Sisolak, in the November 2022 election. (See New Governor Seeks Shift in Nevada Energy Policy.)  

Among policies in Lombardo’s March 2023 executive order was direction to meet the state’s energy demands with a diverse portfolio including solar, wind, geothermal, natural gas, storage and other resources.  

In contrast, the state’s 2020 Climate Strategy called for transitioning away from natural gas to meet the 2050 net-zero emissions goal. A link from NDEP’s website to the 2020 Climate Strategy now goes to a page reading “under construction.” 

NDEP applied for the CPRG planning grant in April 2023 and was awarded the funds in June. 

Neither the PCAP nor CCAP are intended to replace the 2020 Nevada Climate Strategy, an NDEP spokesperson told NetZero Insider. But the technical work and outreach for the two plans will help during revisions of the climate strategy. 

“Currently NDEP’s efforts are focused on the CPRG to ensure that Nevada is well positioned to apply for and secure the unprecedented level of federal funding for the implementation of emissions reduction projects in Nevada,” the spokesperson said in an email. 

Most-emitting Sectors

Nevada’s 2023 GHG inventory includes emissions data from 1990 through 2021 and projections through 2043. In 2021, the state emitted 37.2 million metric tons (MMT) of CO2 equivalent — 21% less than the peak of 47.1 MMT in 2005. 

The transportation sector was the leading contributor to GHG emissions in 2021, accounting for 34% percent of the total. Electricity generation and industry followed, with 30% and 16% of the total, respectively. 

Before 2015, electricity generation was the largest source of the state’s GHG emissions, with transportation in second place. 

The PCAP notes the strong prospects for clean energy projects in Nevada, where the technical potential is 6.27 billion MWh for commercial, residential and utility solar; 1.13 billion MWh for wind; and 54 million MWh for geothermal. 

“This dwarfs annual electricity consumption, which was approximately 39 million MWh in 2021,” the PCAP said. “Based on this, renewable electricity generated in Nevada could supply the state’s annual electricity needs multiple times over.” 

NERC Committee Greenlights Shortened INSM Comments

NERC’s Standards Committee remains focused on meeting FERC’s deadlines, granting another waiver at its meeting Feb. 21 to authorize shortening the comment and ballot periods for the ERO’s proposed standard on internal network security monitoring (INSM). 

FERC directed NERC in January 2023 to submit standards requiring utilities to implement INSM at certain grid cyber systems (all high-impact systems, and medium-impact systems with external routable connectivity) by July 9, 2024. (See FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack.) The standard is being developed under Project 2023-03. 

The approaching deadline for Project 2023-03 was already on the committee’s radar. At its August meeting, members used their authority under NERC’s Standards Processes Manual to authorize shortening the initial formal comment and ballot period from the standard 45 days to as few as 30, and shortening additional comment periods to as few as 20 days. (See NERC Committee Agrees to Shortened Standard Comments.) 

Since the August meeting, the standards drafting team has posted its proposed standard, CIP-007-X (Cybersecurity – systems security management), for an initial comment and ballot period, which ran from Dec. 14 to Jan. 17. The standard failed to pass, reaching only a 15.42% segment-weighted approval. 

Alison Oswald, NERC’s manager of standards development, told the committee that as a result of feedback received during this comment period, the SDT decided that rather than updating an existing standard, it would be best to create a completely new standard, CIP-015-1. This move did not require the committee’s approval, but the team did seek authorization to further shorten additional comment and ballot periods for the standard — after the next one, already scheduled to begin Feb. 27 and last for 20 days — to as little as 10 days. 

While attendees of the meeting had no objection to the request itself, they did request that NERC staff clarify a point of possible confusion: As Oswald explained, the decision to draft a new standard meant the comment period would be listed in NERC’s balloting system as an initial ballot, rather than a follow-up round. After Oswald confirmed that staff would do their best to make sure industry understood the issue, members voted unanimously to approve the shortened comment period. 

Ironically, before the committee authorized shortening the comment period for 2023-03, Oswald had informed it that the initial ballot period for another project — Project 2022-03 (Energy assurance with energy-constrained resources) — had been inadvertently extended. 

The ballot pools for this project were to be opened Jan. 25, the day the comment period began, with ballot pools to be closed Feb. 23 and voting to conclude March 11. Oswald explained that the project’s administrator mistakenly opened the ballot pools three days early on Jan. 22. Because 50 pool members had already joined by the time the mistake was discovered, the team decided to leave the pool open and close it on the scheduled closing day, bringing the matter to the committee’s attention as required by the SPM. 

In a final standards action, the committee voted to approve changing the definition of “Automatic generation control” in NERC’s glossary to fix grammatical issues. The errors were discovered by the team for Project 2022-01 (Reporting ACE definition and associated terms), which was completed last week when NERC’s Board of Trustees approved its proposed glossary changes. 

As NERC Manager of Standards Development Jamie Calderon explained, the SPM states that correcting such errors does not require industry ballot if the Standards Committee agrees that the change “does not change the scope or intent of the associated reliability standard” or impact end users. Members again voted unanimously to approve the update. A NERC spokesperson confirmed that the newest definition will not require a separate vote by the board and will be submitted to FERC with the other definitions approved last week.