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October 9, 2024

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Avangrid ‘Focused on Defeating’ NECEC Referendum

Avangrid (NYSE:AGR) is “focused on defeating” next month’s Maine ballot referendum designed to halt construction of the New England Clean Energy Connect (NECEC) transmission line, CEO Dennis Arriola said Wednesday.

Construction is “well underway” with more than 100 poles installed, Arriola said during a third-quarter earnings call, adding that towns in the path received the first tax payment from the project. A “grassroots campaign” is also underway to sway voters in Avangrid’s direction on the referendum.

Avangrid remains encouraged by the support for NECEC over the last several months as the company attempts to combat what it calls “misinformation” spread by “companies that own fossil fuel generation in New England,” he said.

“We’re focused on defeating the Nov. 2 referendum related to the project, and our growing grassroots campaign is working hard every day to help voters better understand the benefits of the project to Mainers, the economy, the environment and the region,” Arriola said.

NECEC supporters include current Democratic Gov. Janet Mills, former Republican Gov. Paul LePage, labor leaders including the AFL–CIO, Maine chambers of commerce and the Conservation Law Foundation, “just to name a few,” Arriola said.

“There are winners and losers” in the clean energy transition, he said.

“In this case, the winners from this project are going to be the people of Maine, the environment, the local economies, climate change [opponents] in total. But the losers in this are going to be those that basically are providing the fossil fuel generation.”

Energy infrastructure projects, including transmission, often face challenges, and “the challenge is that there are certain parties that may not want that because it impacts their livelihood,” Arriola said.

In addition to the referendum, the Maine Department of Environmental Protection (DEP) held a hearing recently to determine whether it should revoke the permit to construct the NECEC transmission line.

There is no deadline for the decision in the DEP proceeding. Still, the agency can temporarily suspend the construction permit or revoke it entirely, forcing an application for a new one. DEP Commissioner Melanie Loyzim opened the proceeding after a Maine Superior Court ruling in August vacated a 1-mile public land lease to Avangrid subsidiary Central Maine Power. Loyzim said the court’s decision represented a change in circumstance that could warrant a permit suspension. (See Maine Regulators Hear from CMP, Residents on NECEC Permit.)

PNM Merger, OSW Talk

Avangrid is “on track” to close its multi-billion dollar merger with PNM Resources by the end of the year, with just one approval remaining from the New Mexico Public Regulation Commission. Arriola said that 23 of the 24 filing interveners either support the merger directly or have decided not to oppose its approval.

Arriola also touted Vineyard Wind I securing $2.3 billion of construction and term loan financing with nine global lending banks, becoming the first commercial-scale offshore wind project in the U.S. to reach financial close. Construction already has started for the onshore substation and export cable routes, and Arriola said offshore construction will begin in the first half of 2022. “We’ll start delivering clean power to Massachusetts in 2023 and reach full commercial operation in 2024.”

Earnings

Avangrid reported earnings of $111 million ($0.29/share), up $24 million from the same period in 2020 ($0.28/share). Avangrid Networks earned $116 million during the quarter, up from $94 million in September 2020. Avangrid Renewables posted earnings of $12 million during the quarter, down from $25 million in September 2020.

For the first nine months of 2021, consolidated net income was $543 million ($1.56/share), compared to $415 million ($1.34/share) for the first three quarters of 2020.

Call transcript courtesy of Seeking Alpha.

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SPP, Members Begin Response to February’s Winter Storm

SPP staff and stakeholders agreed this week on the need for greater collaboration and coordination between the electric and gas industries as they begin the work of addressing the root causes that led to the first load sheds in the RTO’s 80-year history during February’s winter storm.

The discussion picked up where the Markets and Operations Policy Committee left off two weeks ago, when Texas-based stakeholders complained they had firm contracts for fuel deliveries that were negated by force majeure. (See SPP Markets and Operations Policy Committee: Oct. 11-12, 2021.)

“This happened in 2011, and it will happen again,” Southwestern Public Service President David Hudson said during Monday’s joint quarterly stakeholder meeting, referring to a less severe winter storm that also led to rolling blackouts in Texas. “That’s one of the biggest things hiding in the tall grass that’s not being addressed.”

“We can do everything we can to promote coordination between the industries, but better coordination only gets us so far,” Kansas Corporation Commissioner Andrew French said. “The winterization and the lack of production is the bigger issue.”

French said FERC’s and NERC’s preliminary report on the storm contained numerous “aspirational goals” that individual states begin winterizing all their equipment. The agencies’ joint inquiry placed much of the blame on the natural gas industry’s failure to perform. (See FERC, NERC Share Findings on February Winter Storm.)

“No state is going to step forward and place costs on their producers absent an act of Congress, and I don’t think we can rely on it,” French said.

North Dakota Public Service Commissioner Randy Christmann pointed out that northern energy facilities have been weatherizing for years, but that it doesn’t make sense to do so in southern states “because of the costs of winterization … for those few days when it’s needed.”

“We almost seem to be resigning ourselves that we can’t do much about gas weatherization,” said Dave Osburn, Oklahoma Municipal Power Authority’s general manager. “I just hope we as an industry don’t let the issue go. We have to continue to push this issue, because we certainly don’t want to live through another event like this.”

To that end, SPP COO Lanny Nickell said staff and stakeholders have begun developing recommendations addressing the February outages’ root causes. The Board of Directors ordered the work begin immediately when they accepted SPP’s report on the winter storm in July. (See “Grid Operator Releases Report on Performance During Winter Storm,” SPP Board of Directors/Members Committee Briefs: July 26-27.)

Arkansas Public Service Commission Chair Ted Thomas is leading a task force working on issues related to fuel assurance and resource planning and availability, which the report identified as a Tier 1 issue. The Improved Resource Availability Task Force (IRATF) will report to the board and the Regional State Committee and publish monthly status reports on its work. The group will review staff’s potential solutions and recommendations, provide direction and coordinate with other stakeholder groups as necessary.

“It’s like Thanksgiving when all the food hits the table at the same time,” Thomas said. “You keep the wet stuff wet, the hot stuff hot and the cold stuff cold.”

He said the IRATF’s first efforts could include identifying crucial gas infrastructure that is connected to the electric system, similar to Texas’ attempt to map critical infrastructure.

Nickell said the report’s 81 Tier 2 and Tier 3 initiatives are all in progress, except for those related to transmission planning. The work will be prioritized, tracked and reported through SPP’s comprehensive roadmap process, which sets the grid operator’s initiatives over the next two to five years.

“We don’t want to wait on FERC and NERC,” Nickell said, noting that SPP’s effort “aligns pretty well” with the agencies’ final report.

Completing all the initiatives is expected to last several years, Nickell said.

“As we go forward with the initiatives, we’re going to have to be clear about what SPP can do and cannot do and who has authority over the gas system,” Nebraska Power Review Board Member Dennis Grennan said. “We’re going to have to be very, very clear about how far SPP can go with its solutions.”

SPP Sets New Summer Peak

Bruce Rew, SPP’s senior vice president of operations, told stakeholders that the RTO set a new summer peak load of just over 51 GW on July 28, surpassing the previous record of 50.7 GW set in August 2019. 

SPP called for conservative operations July 29-30 as summer heat continued to bake the Great Plains. Wind energy reached a high output of 20.7 GW on Aug. 8, accounting for 52.2% of SPP’s load at the time. Wind penetration reached 65.3% of the RTO’s generation mix on Sept. 26, when wind produced 14.8 GW of the total load of 22.7 GW.

Rew said 30.5 GW of wind generation is registered in the market, although only 25.8 GW was available as of Oct. 1. He said SPP currently has 283 market participants, with financial-only players outnumbering asset-owning participants, 181-102.

The Western Energy Imbalance Service market’s second quarter saw average hourly load trended slightly downward by 0.2 GWh. The WEIS market is consistently settling an average of 4 to 5 GWh of net energy imbalance generation per day, Rew said.

Sugg: In-person Meetings Soon

SPP CEO Barbara Sugg teased a potential return of in-person meetings in January in acknowledging that “we all have Zoom fatigue.”

Sugg said the MOPC and Strategic Planning Committee will meet Jan. 10-12 in Oklahoma City, and the board and Members Committee will meet Jan. 24-25 in Little Rock, Ark.

“We hope to see you there,” Sugg told stakeholders.

SPP is once again in a return-to-office mode after a previous attempt was scuttled by the COVID-19 Delta variant’s emergence. Staff have begun a hybrid workplace format that allows more flexibility to work from home while still coming to the office. Employees must spend 50% of the time in the office and managers 75% in the voluntary program. Chief People Officer Kelly Carney said an average of 70 staffers can be found daily on the SPP campus.

Sugg also said SPP has begun preparing to claw back and refund $138 million in transmission-upgrade credits, dating as far back as 2008, as it waits on a response to its rehearing request of the D.C. Circuit Court of Appeals’ August ruling that FERC was correct in reversing a retroactive waiver it had granted the RTO over collecting transmission upgrade costs under the tariff’s Attachment Z2. (See “SPP Asks for Z2 Rehearing,” SPP Markets and Operations Policy Committee: Oct. 11-12, 2021.)

“Our favorite topic from years gone by that we can’t get rid of … the gift that keeps on giving,” she said. “This will be a major undertaking for SPP and our stakeholders.”

RSC Elects New Leadership

The RSC met briefly before the quarterly stakeholder reports and elected its leadership for 2022.

SPP’s state regulators approved North Dakota Commissioner Christmann as their president. He succeeds South Dakota Public Service Commissioner Kristie Fiegen, who will remain on the committee.

KCC Commissioner French will serve as vice president, and Iowa Utilities Board Member Geri Huser will remain treasurer. The committee will lose Grennan, who was honored with a resolution for his six years of service. Grennan was the RSC president in 2020 and also served on several high-level SPP stakeholder groups.

“The last six years on the RSC have gone by so fast it’s really unbelievable,” Grennan said.

Grennan is term-limited, and his tenure on the NPRB will end Jan. 1. He is expected to be replaced on the RSC by NPRB Vice Chair Chuck Hutchison.

Oklahoma Corporation Commissioner Dana Murphy said the Seams Liaison Committee’s rate-pancaking subgroup has sent surveys to 100 MISO and SPP stakeholders and the RTOs themselves as it attempts to resolve rate issues on the RTOs’ seam. The SLC meets again Nov. 18 to discuss the survey’s results.

Murphy volunteered to represent SPP on the SLC subgroup when former Texas Public Utility Commission Chair DeAnn Murphy resigned from the commission earlier this year.

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DTE, CMS Oppose Michigan Community Solar Legislation

LANSING, Mich. — Solar energy advocates squared off against Michigan’s largest utilities this week when a legislative committee heard testimony on legislation requiring the state Public Service Commission to promulgate rules for community solar projects.

Executives for CMS Energy (NYSE:CMS) and DTE Energy (NYSE:DTE) said their companies support and are developing solar energy. But they told the Michigan House Energy Committee Wednesday they opposed HB 4715 and HB 4716 because the bills would increase costs to consumers and weaken consumer protections.

The bills’ supporters, who numbered in the dozens before the committee — though most did not testify — said the legislation is needed to ensure smaller projects are developed in rural and poorer areas the utilities might be less interested in developing.

Committee Chair Rep. Joe Bellino (R) has not indicated yet when and whether he will move forward on the bills. In comments during the hearing, Bellino seemed sympathetic to the bills’ idea and urged fellow committee members to tour a community solar project built by Lansing’s municipal utility, the Board of Water and Light.

Bellino, DTE and CMS have been criticized for holding up a separate bill that could expand rooftop solar in Michigan. Bellino’s campaigns have been supported by utility political PACs and individual executives. In the 2020 election, his campaign got $6,000 from the CMS Energy Corporate Employees PAC. Some 30 utility executives, including the then-presidents of both CMS and DTE, contributed from $250 to $1,000 to his campaign.

The two bills are a bipartisan package, with HB 4715 introduced by Rep. Rachel Hood (D) and HB 4716 by Rep. Michele Hoitenga (R).

Hood said the bill give residents a “real opportunity to save on energy bills,” and “equally important” it lets consumers choose the type of energy they use.

HB 4715 requires the PSC to write rules allowing for the creation and financing of community solar facilities and providing bill credits to subscribers. The bill also allows utilities to recover “reasonable interconnection costs” for projects and for handling a community solar subscription base.

HB 4716 creates a new section in Michigan utility law covering community solar facilities and requires a utility to provide bill credits for at least 25 years of the community solar project’s operation.

Two days before the committee meeting, CMS and DTE held a press conference to announce the “MI Community Solar Program,” which would provide subscriber credits to any customer who signs up for the projects run by the utilities. CMS has two in operation, one at Ferris State University and the other at Western Michigan University, with a third being developed in the northern city of Cadillac. DTE has several in metro Detroit. The utility is also developing a community solar project in Ann Arbor that was announced earlier this month.

Spokespersons at the press conference raised some of the issues, such as out-of-state developers coming into Michigan, they would repeat at the committee hearing. When asked about HB 4715 and HB 4716 at the press conference, Knox Cameron, a DTE manager of renewable energy, said, “We’re supportive of the growth of renewables” but that the utilities’ program is already deploying projects.

DTE Vice President for Renewables Chuck Conlen told the committee the bills were not needed and would “expose Michigan to the pitfalls of deregulated electric” suppliers. The utilities can produce power at lower cost, he said.

Sara Nielsen, CMS’ director of transportation, renewables and storage, said the bills “will effectively force the utilities to subsidize other projects at less defined prices.”

In all, she said, the bills will create a “less equitable, less affordable” system.

Also opposing the bills, but not speaking at the hearing, were the Michigan Manufacturers Association, the Mackinac Center for Public Policy, and the Utility Workers Union of America.

Ed Rivet, head of the Conservative Energy Forum, said the two bills help fill in gaps left by the utilities’ projects. What DTE and CMS are doing is needed, Rivet said, and they will create cheaper energy.

But the bills will assure that smaller areas can take advantage of solar energy too. The big utilities “won’t go into the small places where we need them,” Rivet said. “They won’t go into the niche places.

“This legislation empowers both big and small” projects, he added.

Among those supporting the legislation, but not speaking, were officials from the Michigan Catholic Conference, the Associated Builders and Contractors, the Michigan Municipal League, the Michigan Chemistry Council, the Citizens Utility Board of Michigan and the Michigan United Conservation Clubs.

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Xcel Continues Focus on Carbon Reductions

Xcel Energy (NASDAQ:XEL) CEO Bob Frenzel revealed Thursday that there is little space between him and his predecessor when it comes to the clean energy transition.

Speaking with financial analysts during the company’s third-quarter earnings conference call, Frenzel noted Xcel’s leadership position in clean energy under Ben Fowke, who retired earlier this year, and promised more to come.

“We expect, over the next decade, to close the majority of the coal plants on our systems across the country. We’ll be out of coal in the Upper Midwest by the end of this decade,” he said. “We have plans and approved plans to close a coal plant almost every single year this decade.”

Asked how Xcel’s plan to be carbon-free by 2050 could be accelerated, Frenzel said the Democrats’ proposed budget reconciliation bill includes production tax credits for renewable energy that offer a 10-year window to manage the transition.

The company’s integrated resource plan recently filed with Minnesota regulators envisions a full exit from coal by 2030, balanced by the addition of 3.2 GW of universal-scale solar and 2.7 GW of wind. Xcel has targeted an 85% carbon-reduction in Colorado, its other major market, by 2030 with a similar plan.

“Come 2024, we’d have another bite at the apple to think about the remaining assets on our fleet in those transitions,” Frenzel said. “I think what we need is another type of emissions-free generation.”

He said legislation pending on Capitol Hill would expand the U.S. Department of Energy’s funding for research and development. “I think that’s critical for the industry to progress past where we expect to be,” Frenzel said.

Xcel reported earnings of $609 million ($1.13/share) for the quarter, compared to $603 million ($1.14/share) for the same period in 2020.

The results missed analysts’ average expectations of $1.18/share. Xcel said higher electric and natural gas margins and lower operations and maintenance expenses offset additional depreciation and lower allowance for funds used during construction.

The Minneapolis-based company narrowing its 2021 earnings guidance to $2.94 to $2.98/share and issued 2022 guidance of $3.10 to $3.20/share.

Xcel’s share price gained 94 cents Thursday, closing at $64.33.

AEP Earnings up over 2020

American Electric Power (NASDAQ:AEP) also released its third-quarter results Thursday, reporting earnings of $796 million ($1.59/share), above last year’s third quarter of $748.6 million ($1.51/share).

AEP CEO Nick Akins highlighted the energizing of the 287-MW Maverick Wind Energy Center, the second of three proposed North Central Energy Facilities. The three wind farms will eventually provide 1,485 MW of clean energy. (See AEP a Go with $2B North Central Wind Project.)

The company also announced Tuesday it has entered into an agreement to sell its Kentucky operations to Algonquin Power & Utilities for $2.85 billion. (See AEP to Sell Kentucky Operations to Algonquin.)

“Transforming the way energy is generated, delivered and consumed is necessary to support the needs of a clean energy economy, and AEP continues to drive that transformation for the benefit of our customers and communities,” Akins said.

The company’s share price was trading at $84.77 in after hours Thursday, a gain of 47 cents on the day.

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Heat Pump Market Flourishes in Maine’s LMI Communities, Official Says

Maine is hitting a “tipping point” in its campaign to deploy 100,000 air source heat pumps by 2025, and much of that success has been in low- to medium-income households, according to Michael Stoddard, executive director of the Efficiency Maine Trust.

“We’re concentrating a lot on equity issues and how we can make sure that this [technology] is accessible to LMI homes and small businesses,” Stoddard said Thursday at the New Buildings Institute’s Getting to Zero Forum.

In January 2020, Gov. Janet Mills announced a suite of expanded heat pump rebates, including $2,000 for LMI homeowners in the Low Income Home Energy Assistance Program. That amount is double what other homeowners can receive for installing a qualified high-performance heat pump.

“We’re installing thousands per year for the LMI community,” Stoddard said, which is evidenced by a study of installation rates by region.

The densest heat pump penetrations are in the northern, sparsely populated areas of the state, where the median income is low, according to Stoddard. That outcome, he said, “is attributable to savvy customers, who are motivated to think about how they’re going to heat their homes.”

Maine surpassed 75,000 total heat pumps last year and installed 28,000 in 2020 alone, he said, adding that the state is on track to reach 180,000 installations by 2025. But it has a loftier goal of 500,000 installations by 2030, so Stoddard says market momentum is critical right now.

“The good news is that we’ve established that we can get on the trajectory we need to be on,” he said. “The big question is going to be, can we sustain it?”

To ramp up Maine’s heat pump market, Efficiency Maine had to demonstrate that the technology works in cold climates and establish a strong installer network. The agency has more than 1,000 registered heat pump vendors, according to Stoddard. Vendors must be trained and certified and sign a code of conduct, he said, and Efficiency Maine set “very high standards” for approved heat pump models.

“There are many models out there that won’t do well in cold weather,” he said, adding that approved systems can make heat down to ‑20 degrees Celsius in some cases and are highly efficient above 0 C.

An Efficiency Maine survey found that 20% of newly constructed homes in the state over the last three years had heat pumps as the sole heating source. Another 17% had heat pumps with a fossil-fuel system as backup.

For retrofits, Stoddard said, people are putting in one or two heat pumps to displace as much of their central system as possible but keeping the central system as backup. The different systems, he added, compete with each other.

“It would be vastly more economical and better for the environment if the heat pumps would run all the time, and then the central heating would only come on as needed,” he said. “But the thermostats call when they call, and we have to teach consumers how to optimize that.”

Relatively low electricity prices in Maine have helped show the economic benefit of choosing heat pumps. The state’s rates have been at 17 to 18 cents/kWh, while other parts of the Northeast pay 23 to 24 cents/kWh, Stoddard said.

Heat pumps also are competing with high-priced heating fuels.

“A lot of our homes and businesses are heated with oil and propane, and that makes the economics of heat pumps quite strong,” he said. “It’s much tougher against natural gas prices, but given the price swings that we’ve experienced in our state with oil and propane, customers are quite interested in options.”

If heat pumps are going to continue to compete on price, Stoddard says policymakers need to be cautious about how they seek to pay for climate solutions.

“If policymakers and advocates think they’re going to load up all the solutions for climate change by putting that cost on ratepayers, you have to ask yourself if that’s going to be sending the right price signal to electrify,” he said. “I’m not convinced that that’s the best way to pay for it.”

And rebates cannot be a long-term solution either.

When it’s “politically palatable,” Stoddard said, states should put codes and standards in place that call for heat pumps over polluting systems that “frustrate” climate goals.

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NJ Launches Grid Modernization Study

Rapidly growing solar and offshore wind generation will require a modernization of New Jersey’s distribution interconnection process, the Board of Public Utilities (BPU) said Tuesday as it held the first hearing in a seven-month study of how best to prepare for the extra stress.

The agency said it plans to conclude the study in May with recommendations. The topics to be studied will include an assessment and modernization of the processing of interconnection requests, identifying the challenges with the current connection system and looking for ways to improve coordination with PJM, said Guidehouse, a global energy consultant hired to lead the project.

The BPU’s hearing notice said the scope will include “the current distribution grid interconnection policies and process, and potential improvements that will enable faster grid modernization and higher levels of distributed energy resource (DER) absorption.”

New Jersey law sets different review procedures for electric distribution companies: Level 1 for inverter-based customer generation of 10 kW or less; Level 2 for customer generation of 2 MW or less, and Level 3 for customer generation that doesn’t qualify for Level 1 or 2.

The second hearing, on Nov. 16, will be devoted to testimony from environmentalists, energy developers, trade groups and other stakeholders on potential improvements. The BPU expects to have a draft report prepared for public review on March 1.

The initiative stems from the state’s Energy Master Plan, and Gov. Phil Murphy’s commitment to set the state on a path for 100% clean energy by 2050, said Jim Ferris, the BPU’s bureau chief for new technology.

“To enable clean energy to be generated at an accelerated pace, and as effectively and efficiently as possible, New Jersey’s interconnection rules and processes require updating,” Ferris said as he opened the hearing. Modernization strategies outlined in the masterplan include “requiring utilities to establish integrated distribution plans and the modernization of interconnection standards,” he said.

Clean Energy Growth

The 290-page master plan describes grid modernization as the “backbone on which all other efforts to transition to a clean energy economy will rely.” The plan sets a goal of 32 GW of solar generated electricity, 11 GW of offshore wind and 9 GW of storage by 2050.

The state currently has about 3.65 GW of solar energy generating capacity, and the BPU has awarded offshore wind contracts totaling 3.758 GW, including 2.658 GW awarded in June. (See NJ Awards Two Offshore Wind Projects.) The BPU expects to make three more rounds of offshore wind awards by 2033 for a total of 7.5 GW.

Industry stakeholders, among them developers and environmentalists, welcomed the BPU’s initiative in seeking stakeholder input into the modernization process.

Under the current process, a customer proposes a clean energy project and submits an interconnection application and agreement to tie the resulting project into the grid. The electric distribution company (EDC) then identifies and installs network upgrades, if needed, and the customer receives approval to install the project. After a final inspection, the developer seeks approval to operate.

Eric Miller, energy policy director in New Jersey for the Natural Resource Defense Council, encouraged the BPU to look beyond the interconnection process and consider a broader array of issues. Factors such as the charging load from electric vehicles and building electrification, energy storage, demand response, and peak load reduction should all be considered in the modernization discussion, he said, adding that “it touches on everything that’s grid connected or could interact with the grid.”

Steven S. Goldenberg, representing the New Jersey Large Energy Users Coalition, said one difficulty for solar developers is that while the BPU initiates a two-year timeline from the start of a project to approval, PJM operates on a timeline as long as three years. “So, the disconnect can be critical for certain project developers.”

Questions over Resources, Timelines

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, said a key concern of his members is what they see as the lack of resources at EDCs to handle the growing number of solar connections that need to be made, which results in significant project delays.

“It’s a huge problem because of the number of applications,” he said. While the EDCs are responsible for interconnections, the resulting increase in solar energy could reduce demand for the EDC’s power, he said.

“What we’re asking them to do is to hire more people and to put resources in so that they can get less revenues,” he said. “It’s an irrational process.”

DeSanti said his organization would also like the hearings to focus on “cost sharing,” with an aim of creating a set of standardized per-KW fees paid by developers, with the understanding that costs not covered by that would be borne by ratepayers.

Scott Elias, senior manager of Mid-Atlantic state affairs for the Solar Energy Industries Association, said that as the number of projects arriving at the EDCs grows — especially larger and more complex developments — there is a need for the utilities to “pre-screen” them to assess the interconnection costs in advance.

“We’ve seen this play out in other states where this helps reduce the number of speculative applications and it also helps prioritize projects,” he said. He also suggested that the state set up a uniform set of interconnection fees for solar projects based on market segment type and size.

“What we need is to provide certainty to developers of big systems, that their interconnection costs will be manageable and give them the security they need to move forward with their projects,” he said.

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US Bankruptcy Judge Continues to Mull Akin Gump’s Final Fees

A U.S. bankruptcy court has again delayed the final payment in a $67 million legal bill that a national law firm charged FirstEnergy Solutions in its restructuring case.

Judge Alan Koschik appeared to be troubled Tuesday by the responses of lawyers and lobbyists with Akin Gump Strauss Hauer & Feld in an open court hearing. They were defending about $2.8 million in fees for, among other things, the work of a lobbying team the firm sent to Ohio to help engineer the passage of the now infamous Ohio H.B. 6, passed in July 2018.

Koschik deferred a final ruling on the fees until a Nov. 16 hearing, when he will announce his decision from the bench. The court has delayed approval of the final payment for months as Koschik awaits the outcome of an ongoing Justice Department investigation into the passage of H.B. 6.

That investigation has so far led to the indictment of former Ohio Speaker Larry Householder (R) and four associates on federal racketeering charges, and the dismissal of FirstEnergy’s (NYSE:FE) former chief executive and four others over the company’s $61 million in dark money to bankroll Householder’s multiyear campaign engineering passage of the bailout. FirstEnergy paid a $230 million fine as part of a three-year deferred prosecution agreement that dropped wire fraud charges if the company continues to cooperate.

The Akin lobbying team admitted in affidavits filed earlier this month and in testimony Tuesday that it worked hand-in-glove with Juan Cespedes, principal of the Oxley Group, a Columbus firm and FES lobbyist at the heart of the federal probe

Cespedes and political strategist Jeff Longstreth pleaded guilty to a racketeering conspiracy charge in October 2020 but have not been sentenced, pending their cooperation with the ongoing probe. Householder has pleaded not guilty and awaits trial.

“I have to think about all of this but … my biggest concern with all of this — and I don’t know what I’m going to do with it is … we had a major law firm with a lobbying wing representing the debtors during the course of this case, heavily involved, a lot of fees involved because of a lot of work was being involved,” Koschik said following nearly an hour of questioning Akin’s lobbyists and two top trial lawyers who have handled the bankruptcy case in court since March 2018.

“And somehow yet … while this case is pending in this court, it has found itself to be … indictment-adjacent,” Koschik said. “There are people that [Akin] was doing work with, some of them were being paid pursuant to an order from this court, namely an ordinary course [of business].”

Koschik noted that some of the Ohio operatives that Akin’s lobbying team worked with have been indicted “in connection with an effort that was driven in large part to get a subsidy for the nuclear plants that were very much a part of this case.”

“And it’s a little irksome to me that while I’m supervising this case, that happened. What do I do with that? Why should I include that? [Why should] all of the fees for the lobbying effort, $2.8 million … be allowed or allowed in full, when what has happened, has happened?

H.B. 6 created a $1.1 billion public bailout of two unprofitable Ohio nuclear plants that FES, now called Energy Harbor, continues to operate, though the state legislature rescinded the subsidies earlier this year amid the ongoing Justice Department investigation into what it described as the worst corruption scandal in the state’s history.

Akin has portrayed the efforts of its public policy team on the ground in Columbus as standard operating procedure, not unusual in any way and legally permissible.

Koschik on Tuesday questioned four members of the Akin lobbying team who worked in Ohio on H.B. 6 and each said they were surprised by the indictments, though one admitted that he was aware at some point that the dark money group, Generation Now, was tied to Householder.

Abid Qureshi, one of the Akin attorneys who has represented the company during the bankruptcy proceedings, said all the parties — including creditors who were owed significant amounts of money — were aware of the decision to field a lobbying team in Columbus and the decision to fund those efforts.

“With respect to all of the … creditor constituencies, when these decisions were being made to have FES, to have the debtors make these political contributions, to have the debtors use their efforts to get H.B. 6 passed, to have the debtors assist in the effort to defeat the referendum that followed the passage of H.B. 6, there was continuous dialogue with all of the stakeholders in the bankruptcy case,” he told the court.

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Nevada Adopts Clean Cars Rule, Allows Early Credits

Although Nevada’s newly adopted Clean Cars regulation won’t take effect until model year 2025, the rule will allow auto manufacturers to start earning zero-emission vehicle credits starting in January.

The so-called early action credits have won the praise of environmental advocates, who say it will help bring more zero-emission vehicles (ZEVs), and a greater variety of models, to Nevada car buyers in a timelier manner.

The early ZEV credits will be available for model year 2022, 2023 and 2024 vehicles that automakers deliver for sale in Nevada.

Western Resource Advocates (WRA) said in a release that Nevada’s ZEV crediting system “offers a promising model for other states contemplating adoption of ZEV standards.”

“The Nevada plan … provides certainty to the auto industry while also ensuring the rule attains the maximum environmental benefits,” the group said.

Final Approval Granted

The Nevada Legislative Commission voted to pass the Clean Cars Nevada regulation on Friday in the final step of the approval process. Nevada now joins 14 other states and the District of Columbia in adopting Clean Cars regulations.

Under the federal Clean Air Act, states have an option of adopting California’s Clean Cars rules instead of using federal vehicle-emission standards.

California’s current Advanced Clean Cars regulation, which the California Air Resources Board (CARB) first adopted in 2012, includes two programs. The low-emission vehicle (LEV) program aims to reduce tailpipe emissions of greenhouse gases and smog-forming pollutants.

The second component, the ZEV program, has a goal of increasing the supply of zero-emission vehicles available to car buyers in the state.

Clean Cars Nevada includes both the LEV and ZEV programs. The Nevada Department of Environmental Protection developed the regulation.

“Clean Cars Nevada is a huge victory for the Silver State,” Nevada Gov. Steve Sisolak said in a release. “Transportation is the No. 1 source of greenhouse gas emissions in Nevada and drives disproportionate pollution burdens for historically underserved communities.”

Calculating Credits

ZEV credit requirements are calculated as a percentage of vehicles that a car maker sells in the state. Under California’s Advanced Clean Cars, the percentage has been increasing over time and will top off at a 22% requirement for model year 2025.

That creates an interesting timing issue for Nevada, where the Clean Cars program starts with model year 2025 and a 22% ZEV credit requirement.

To help meet the new requirement, automakers can bank early action credits for model years 2022, 2023 and 2024 and then apply them toward the ZEV requirement in model year 2025.

After that, car manufacturers can use a proportional credit allowance to help meet Nevada’s credit requirement for model year 2026. The proportional credit is based on an automakers’ ZEV credit balance in California.

In general, groups such as WRA have concerns about the proportional credit, which they say encourages  manufacturers to sell electric vehicles in California rather than in other states.

But in Nevada, the use of the proportional credits is delayed to model year 2026. The Nevada plan gained the support of auto manufacturers, environmental advocates and state officials, according to WRA.

“If you do credits poorly, you essentially get a rule that’s less effective,” WRA’s Transportation Electrification Manager Aaron Kressig told NetZero Insider.

The ZEV credit is determined from factors including the distance a vehicle can travel on a single charge and whether it is a plug-in hybrid or fully electric. With a 22% ZEV credit requirement, ZEVs will account for about 8% of cars available for sale in the state that model year, WRA has estimated.

ACC II on the Horizon

The adoption of Clean Cars Nevada comes as CARB is in the process of crafting an Advanced Clean Cars II (ACC II) regulation for model years 2026 and beyond. (See CARB Plan Would Allow Interstate Transfer of ZEV Credits.)

The regulation is expected to require auto manufacturers to provide 100% zero-emission cars for sale by 2035, consistent with a 2020 executive order from Gov. Gavin Newsom.

CARB expects to present ACC II rules to its board in June 2022.

That raises the question of whether Nevada will move to ACC II. Without a change to Clean Cars Nevada, the ZEV credit requirement would remain at 22%.

NDEP said in an email that it is participating in the development of ACC II, along with other Clean Cars states.

“NDEP will carefully consider the proposal and vet it for adoption in Nevada with stakeholders here before making a recommendation to the Nevada State Environmental Commission on whether to adopt the anticipated rulemaking for Nevada,” the agency said.

Kressig said he expects to see Nevada and other Clean Cars states start wrestling with the issue of a new regulation in 2023, after California is expected to adopt the new rule.

“All those states will have to reevaluate whether they want to take on ACC II,” he said.

States that have adopted Clean Cars regulations include California, Colorado, Connecticut, Maine, Maryland, Massachusetts, New Jersey, New York, Oregon, Rhode Island, Vermont and Washington as well as the District of Columbia. They were joined this year by Virginia, Minnesota and Nevada.

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Women Advocate for Greater Representation at COP26

Women, especially Indigenous women, should have a bigger role in the 26th Conference of the Parties, as they are largely impacted by the global climate crisis but are overlooked in policy decision making, according to the feminist coalition Women’s Earth & Climate Action Network.

Osprey Orielle Lake, founder and executive director of the network, presented a call to action to the United Nations General Assembly on Tuesday, including demands to rapidly halt fossil fuel extraction and build on community-led renewable energy solutions.

Over 140 groups signed the call to action before Lake presented it during the U.N. General Assembly’s meeting “Delivering Climate Action: For People, Planet and Prosperity.”

The document asks government leaders and financial institutions to prioritize women’s leadership and equity by protecting the rights of Indigenous communities disproportionately impacted by climate change, but who can also lead solutions on the frontlines.

“We are not willing to die because of the insistence upon endless economic growth and extractive industries that particularly harm women and Indigenous, Black, Brown, island and global south peoples,” Lake said Tuesday at the assembly.

COP26 represents the opportunity to build a pathway to limiting global warming to 1.5 degrees Celsius. It is also an opportunity, Lake said, to do so in a way that helps the people worst affected to build resilience in their own communities.

The call to action highlights natural gas, nuclear power plants, hydroelectric dams, forest offsets, carbon trading and carbon capture and storage as “false solutions” that continue to displace Indigenous communities.

“It’s not ok to tell us we are being unreasonable with our demands for climate justice because we don’t understand what is possible in the political sphere, or the business or financial institutions,” Lake said to the assembly. “We will not allow for sacrifice people or sacrifice zones, corporate colonialism or incremental transitions to renewable energy.”

Role of Financial Institutions

The call to action outlines steps for financial institutions to pull investments from fossil fuel extraction and redirect those resources to solutions that are beneficial to Earth’s climate and environment.

Banks should require clients engaged in fossil fuel extraction to develop plans to phase out their fossil fuel operations to make a positive difference in a timeframe that aligns with the International Panel on Climate Change’s report on the impacts of global warming of 1.5 degrees C, according to the call to action.

In addition, it said that financial institutions should decline financing to companies that refuse to publish plans to do so.

The 60 largest commercial and investments banks collectively financed $3.8 trillion in fossil fuel companies between 2016 and 2020 after the Paris Agreement was signed, according to a report published in March by a collection of climate organizations titled Banking on Climate Chaos 2021.

“The real problem is not that we don’t have a plethora of solutions from agroecology to Indigenous knowledge, from regenerative energy to feminist economics and climate policies,” Lake said. “The problem is the insistent structural interference that those in power are exercising in response to people taking real action.”

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New York Regulators Deny Astoria, Danskammer Gas Projects’ Air Permits

New York regulators on Wednesday denied air permits for the Astoria and Danskammer Energy Center gas-fired generator projects, saying that the proposed facilities would not comply with the state’s climate law.

The projects “would be inconsistent with or would interfere with the statewide greenhouse gas emissions limits established in the Climate Leadership and Community Protection Act (CLCPA),” New York Department of Environmental Conservation Commissioner Basil Seggos said in a statement. Both developers “failed to demonstrate the need or justification” for their projects “notwithstanding this inconsistency,” he said.

The DEC issued draft air permits for both projects in July but asked for input on potential inconsistencies with the CLCPA.

Gov. Kathy Hochul applauded the decision.

“Climate change is the greatest challenge of our time, and we owe it to future generations to meet our nation-leading climate and emissions-reduction goals,” she said in a statement.

Danskammer Energy’s proposal sought to build a 536-MW natural gas-fired, combined cycle generation facility at the site of the existing 532-MW Danskammer Generating Station in Newburgh, N.Y. NRG Energy’s (NYSE:NRG) Astoria proposal included construction of a 437-MW simple cycle, dual-fuel peaking generator in Queens.

The department determined that the projects would be a new source of a “substantial amount” of direct and upstream GHG emissions, according to notices to Danskammer and NRG. In addition, the DEC said the projects would “constitute a new and long-term utilization of fossil fuels to produce electricity without a specific plan in place to comply with” the CLCPA.

As presented, the department said, the developers’ plans to meet the CLCPA’s requirement to be emission-free by 2040 are “uncertain and speculative in nature.”

NRG “simply assumes that, prior to 2040, the project will be able to utilize hydrogen, renewable natural gas or some other fuel that is considered zero-emissions under the climate act,” the DEC said, while Danskammer has not established the feasibility of using hydrogen or RNG from a supply or GHG emission perspective.

NRG is reviewing the state’s decision, according to Tom Atkins, vice president of development.

“It’s unfortunate that New York is turning down an opportunity to dramatically reduce pollution and strengthen reliable power for millions of New Yorkers at such a critical time,” Atkins said in a statement to NetZero Insider.

The Astoria project would have been fully convertible to green hydrogen in the future, according to Atkins.

“New Yorkers deserve both cleaner air and reliable energy to ensure the lights stay on for our small businesses, homes, schools and hospitals when they need it most,” he said. “That’s what this project would have delivered, and that’s what NRG had been fighting for along with labor leaders, the small business community and local Queens residents. We appreciate their support during this difficult process.”

The company, he said, is “deeply disappointed” in the department’s decision.

“NRG will continue to find ways to help New York achieve its emissions goals,” he said. “In the meantime, our current Astoria plant will continue to operate to help ensure the lights stay on in New York City, as that remains the most important thing.”

Danskammer Energy did not respond to a request for comment on the DEC’s decision.

Reactions

The DEC was “right to reject” the applications, Peter Iwanowicz, executive director of Environmental Advocates NY, said in a statement.

“This is a tremendous decision by DEC and another for the growing list of the Hochul administration’s actions that will provide clean air and a healthful environment for the 20 million people that call New York home,” he said.

The decision to deny the air permits “tees up similar outcomes” for other projects in the permitting process, such as the Gowanus repowering project in Brooklyn, Sierra Club said in a statement.

Astoria Generating, a wholly owned subsidiary of Eastern Generation, filed a plan with the New York Department of Public Service in 2018 to replace 32 oil and gas generating units at the 640-MW Gowanus facility with eight gas-powered units (Case 18-02956). Gowanus is sited on four floating barges moored in Gowanus Bay in Brooklyn.

“Gov. Hochul made clear that fracked gas power plants have no place in New York’s energy future, heeding the call of environmental justice and climate advocates and community members who organized tirelessly for this climate victory,” said Allison Considine, New York campaign representative with Sierra Club.

Given previous remarks by Seggos on the Danskammer project, the DEC’s decision was not surprising, according to a statement from State Sen. James Skoufis (D).

“I stand ready to partner with local communities, buildings trades and environmental stakeholders to put forward a project for the existing Danskammer site that both aligns with New York’s climate laws and serves the needs of our area,” he said.