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February 6, 2025

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Senate Wildfire Bills Address Tx Corridor Clearing, Other Measures

A bipartisan bill in the U.S. Senate would make it easier for utilities to clear trees around power lines on U.S. Forest Service land by not requiring a timber sale for the cut-down material. 

Senate Bill 349, also known as the Fire-Safe Electrical Corridors Act, is one in a package of three bipartisan fire-safety bills that Sen. Alex Padilla (D-Calif.) announced Feb. 3.  

Another bill in the package is the wide-ranging Wildfire Emergency Act, or SB 350. Among its provisions are creating a prescribed fire training center in the West and speeding up the installation of wildfire detection equipment on the ground and in space. 

The third bill, SB 336, would give homeowners a tax exemption on money they receive through state programs to protect their homes from natural disasters. 

The bills come as the Los Angeles area starts to recover from last month’s severe wildfires that have been called the worst natural disaster in the city’s history.  

But California is not alone in facing wildfire threats. Wildfires burned 8.8 million acres across the U.S. last year, with about 1 million acres of that land in California. 

“Montanans see firsthand the effects that catastrophic wildfires have on our communities,” Sen. Steve Daines (R-Mont.) said in a statement. Daines and Padilla are cosponsors of the Wildfire Emergency Act and the Fire-Safe Electrical Corridors Act. 

Among the 11 sponsors of SB 336, the Disaster Mitigation and Tax Parity Act, are Padilla and Sens. Adam Schiff (D-Calif.), Thom Tillis (R-N.C.) and Bill Cassidy (R-La.). California, North Carolina and Louisiana are states that offer grants to homeowners to take steps such as removing fire-prone vegetation around their homes or strengthening roofs or foundations. 

“Homeowners should not face additional taxes for wanting to protect their homes,” Schiff said in a statement. 

All three bills were introduced Jan. 30 and referred to committee. 

Tree Removal Targeted

Under SB 349, the Forest Service could give electric utilities standing permission to remove hazardous trees near power lines within existing rights-of-way. A timber sale would not be required as part of the tree removal. But if a utility opts to sell the cut-down trees, the proceeds — minus transportation costs — must be given to the Forest Service. 

Although the USFS now allows utilities to cut down and trim trees in utility corridors, some forest managers view the law as forbidding removal of the material, Padilla’s office said in a release. As a result, dry fuels can build up beneath utility lines. 

“This bill would help reduce the risk of wildfires on forest lands by ensuring the clearing of existing corridors and give certainty to utilities,” Padilla’s office said. 

Three of California’s largest or most destructive fires were started by electrical equipment, the release noted. Those include the 2021 Dixie Fire, which burned 963,309 acres, making it the second-largest wildfire in state history. The blaze started when a tree fell onto a PG&E distribution line. 

Powerlines also were blamed for the 2017 Thomas Fire, which charred 281,893 acres, and the 2018 Camp Fire, which destroyed 18,804 buildings and killed 85 people, according to California Department of Forestry and Fire Protection (Cal Fire) statistics. 

The wildfire crisis “demands more proactive responses from the federal government,” Padilla’s office said in a fact sheet on SB 350. 

The Wildfire Emergency Act would create an energy resilience program at the Department of Energy to ensure that critical facilities, such as hospitals, schools, utility stations and police stations, can keep operating during wildfires. The bill would authorize $100 million for retrofits. 

The bill would expand a Department of Energy weatherization grant program to give low-income households up to $13,000 for wildfire-hardening measures, such as ember resistant roofs or gutters. 

The bill also would allow the Forest Service to pilot the use of private financing to restore wildfire-damaged forests. And the bill would allow the expansion of up to 20 existing collaborative forest restoration projects. 

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FERC Approves ISO-NE Capacity Market Collateral Requirements

FERC has accepted ISO-NE’s proposal to increase collateral requirements for generators participating in its capacity market, rejecting the New England Power Generators Association’s (NEPGA’s) arguments the changes violate the filed rate doctrine. 

The changes to the RTO’s financial assurance policy (FAP) are intended to reduce the risks of generators defaulting on pay-for-performance charges incurred during capacity scarcity events (ER24-3071). 

The commission ruled Jan. 31 that the updates “will better protect the market against the risks of socialized defaults and failure to pay non-performance penalties resulting from capacity sellers with insufficient corporate liquidity.” 

The policy revisions will create a corporate liquidity assessment, which will evaluate each generator’s “ability to pay potential penalty payment obligations associated with its CSO [capacity supply obligation] within the applicable Capacity Commitment Period (CCP), over a forward-looking rolling six months.” 

This assessment will categorize participants as low, medium and high risk, and the categories will be used to determine the generators’ collateral requirements. 

The changes took effect Feb. 1, 2025, and will impact CSOs beginning June 1, the start of 2025/26 CCP, which corresponds to Forward Capacity Auction 16.  

The implementation of the revisions will coincide with a major increase in non-performance penalty rates, which also take effect the same date. The penalty rate, which increased from $3,500/MWh to $5,455/MWh for the 2024/2025 CCP, will increase to $9,337/MWh on June 1, 2025. 

Pay-for-performance penalties can pose significant risks to resources with CSOs. Non-performance charges totaled $62.7 million across two scarcity events during summer 2024. Oil resources and non-combined-cycle dual-fuel resources took large penalties during these events, while imports took in nearly $29 million in performance credits. (See NEPOOL Markets Committee Briefs: Dec. 10, 2024.) 

ISO-NE estimated the new collateral requirements will increase the total financial assurance obligations for CSOs in the 2025/26 CCP by about $72 million to $90 million. Generators that meet the “low risk” classification will not be subject to the higher collateral requirements. 

“By requiring CSO holders deemed as medium risk and high risk to provide increased collateral, the FAP Revisions can reduce the risk of socialized defaults,” FERC ruled. 

‘Post Hoc Tinkering’

In its protest of ISO-NE’s proposal, NEPGA argued that applying the updated requirements to existing CSOs would violate FERC’s filed rate doctrine, which prohibits retroactive changes to rates. 

“The FAP changes, if applied to CSOs beginning with the FCA 16 Capacity Commitment Period, would change the financial assurance requirements (the legal consequences) of assuming a CSO in FCAs 16-18 held in 2022 – 2024,” NEPGA wrote. 

“The doctrine forbids ‘post hoc tinkering’ to correct or otherwise alter prior rates, terms and conditions, such as the CSO obligations and entitlements offered and agreed to in FCAs 16-18,” the association added. 

NEPGA alsoargued that, even if the revisions do not violate the filed rate doctrine, increasing the collateral requirements for existing CSOs could decrease investor confidence in market stability, potentially accelerating retirements and reducing system reliability.  

FERC rejected NEPGA’s argument regarding the filed rate doctrine, noting the commission “previously found that the terms and conditions of performance and other obligations that are a part of forward capacity markets may be revised, even after a forward auction for a future delivery year is completed, if the changes are made prospectively and after notice.” 

The commission added that the financial assurance requirements for the upcoming CCP “have not been calculated or posted,” and the changes to the policy accepted by FERC “will only alter future data inputs to these formulas.” 

Responding to NEPGA’s concerns that the revisions still would have negative effects on the market even in the absence of a filed rate violation, FERC wrote that “capacity suppliers had no reasonable expectation that the FAP provisions would remain unchanged, and to the extent that NEPGA members considered existing FAP provisions in formulating their offers, they did so at their own financial risk.” 

NEPGA expressed disappointment with FERCs ruling, saying in a statement that the changes will impose “new, higher costs on generators well after they assumed a Capacity Supply Obligation, and, therefore, have no way of reflecting these increases in market offers.” 

The group added that it is reviewing the order and “assessing potential next steps.” 

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FERC Sets Missouri Co-op’s Tx Rate for Hearing

FERC has ordered hearing and settlement proceedings over a Missouri electric distribution cooperative’s effort to split from the Wabash Valley Power Association and earn rates on its own as a transmission owner in MISO.

Citizens Electric Corp., currently a member of the Wabash Valley Power Association, is striking out on its own and has purchased two planned transmission assets from the association while still taking service as a third-party customer through mid-2028. Citizens hopes to exit Wabash by June.

But FERC in a Jan. 31 order said the rates Citizens proposed might not be just and reasonable, singling out a proposed depreciation rate and one of the lines for not being proven to be beneficial (ER25-324). While FERC gave the go-ahead for rates to become effective Feb. 1, it subjected them to refund.

Citizens is member-owned and borrows from the U.S. Department of Agriculture’s Rural Utilities Service. While not a public utility and exempted from FERC regulation, the cooperative agreed to a commission review of rate recovery. The MISO Board of Directors on Jan. 23 approved Citizens as a transmission owner.

Citizens bought a $117.5 million portion of the jointly planned, 138-kV Grand Tower Project line and substation rebuild, a baseline reliability project approved under MISO’s 2023 Transmission Expansion Plan (MTEP 23). It also purchased the Salem Bulk Project, a new 69-kV line approved as an “other” reliability project in MTEP 23.

FERC decided one of the transmission projects didn’t meet the threshold for rate incentives.

FERC said Citizens did not prove that Salem Bulk Project ensures reliability or reduces congestion costs because of its status as an “other” project under MTEP. In MISO, “other” reliability projects aren’t held to the same level of review as baseline reliability projects, which are built to meet NERC criteria. FERC said the project lacks “a fair and open regional transmission planning process that considers and evaluates projects for reliability or congestion.”

FERC also said it wasn’t convinced Citizens’ proposed 2.75% depreciation rate in the formula is fair. The Rural Utilities Service uses a 2.75% depreciation rate, and Citizens borrowed it, explaining it didn’t conduct its own depreciation study.

Citizens agreed ahead of FERC’s decision that its rate formula would be subject to refund with interest.

Otherwise, FERC granted Citizens’ request for the Construction Work in Progress (CWIP) Incentive and Abandoned Plant Incentive on the Grand Tower Project. FERC agreed the project presents a “cash flow risk” that the CWIP can alleviate while helping avoid rate shocks to Citizens’ transmission customers. Finally, the commission allowed Citizens’ proposed return on equity of 9.98% and the 50-basis-point adder for RTO participation.

Christie Faults ‘Check-the-box’ Tx Incentives

As he has with past orders on rate incentives, Chairman Mark Christie dissented in part from the order, blasting FERC’s incentives approval as a “check-the-box” exercise.

Christie took issue with approval of the CWIP and Abandoned Plant incentives, saying the commission eschewed a “fact-specific, careful evaluation of balancing the needs of consumers and the benefits to investors based on the nature of the transmission projects at issue.” He added that “every transmission developer seems to cite the same” financial and regulatory risks for projects.

Christie also said the RTO participation adder “increases the transmission owner’s ROE above the market cost of equity capital” and is “an involuntary gift from consumers.”

“There has been and continues to be something really wrong with this picture,” he said, calling again to limit the adder to the three years following initial RTO membership.

Christie also pointed out that FERC approved incentives for a transmission project that doesn’t yet have state approval for construction.

“No state CPCN [certificate of public convenience and necessity] proceeding has been conducted reviewing both need and prudence, yet the commission grants the incentive anyway,” he wrote. “Although the regional transmission planning process is only one rebuttable presumption … allowing qualification for incentive rate treatment, reliance on regional transmission planning in lieu of state approval to construct is one of the major problems with FERC’s policy. This practice is indefensible and always has been.”

He said MISO’s transmission planning is “not remotely the equivalent of a serious, litigated” CPCN.

Christie repeated concerns that the CWIP Incentive “effectively makes consumers the bank for transmission developers,” and the Abandoned Plant Incentive “effectively makes them the insurer of last resort” — all without the benefits of interest or premiums.

Christie said the case “graphically illustrates the fundamental unfairness of the commission’s practices regarding incentives” and demanded a revisit of FERC Order 679, which makes any transmission project designed to increase reliability or reduce congestion eligible for incentive ratemaking.

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State Briefs

CALIFORNIA 

PUC Approves SCE Rate Hike to Cover Wildfire Victim Payments

The Public Utilities Commission voted to allow Southern California Edison to raise rates to cover payments it made to victims of the devastating 2017 Thomas wildfire. 

The vote means that more than $1.6 billion of the $2.7 billion Edison paid to more than 5,000 fire victims will be covered by customers. The rest will be paid by shareholders. Most customers will see an increase to their monthly bill of about $1, the company said. 

SCE also asked the PUC to approve a second rate increase for $5.4 billion in payments to victims of the 2018 Woolsey fire, which it will consider later. 

More: Los Angeles Times 

CONNECTICUT 

Eversource, Avangrid Sue PURA over Decision-making Process

Eversource Energy and Avangrid have sued the Public Utilities Regulatory Authority, saying Chair Marissa Gillett has frozen the agency’s other commissioners out of the decision-making process since the start of 2020. 

As a result, the lawsuit states hundreds of decisions involving the utilities and their subsidiaries have been affected. Last month, some Democratic lawmakers accused the utilities of trying to intimidate public officials. Meanwhile, Republican leaders said the litigation signifies problems with the regulatory system. 

Gov. Ned Lamont (D) responded to the lawsuit, publicly accusing the utilities of waging a campaign to oust Gillett, whom he appointed. 

More: CT Insider; CT Mirror 

INDIANA 

URC Approves Duke Rate Increase

The Utility Regulatory Commission approved a $395 million rate increase for Duke Energy. Duke originally requested an increase of $491.5 million, which would have raised average residential bills by as much as $27.63/month in two phases. 

More: WXIN 

MARYLAND 

Talen, PJM Reach Agreement to Keep Coal, Oil Generation Online

Talen Energy reached an agreement with PJM and the Public Service Commission to extend operations at its 1.3-GW coal-fired Brandon Shores power plant and 774-MW oil-fired H.A. Wagner units until May 31, 2029. 

Talen on Jan. 27 said the agreement is “intended to provide the power necessary to maintain grid and transmission reliability in and around the City of Baltimore until necessary transmission upgrades to provide reliable power to the area from other sources are complete.” 

If approved by FERC, the settlement will allow Talen to run the plants well beyond their May 2025 retirement dates. 

More: POWER Magazine 

MINNESOTA 

Gov. Walz Appoints Partridge to PUC

Gov. Tim Walz (D) appointed Audrey Partridge to a six-year term on the Public Utilities Commission. Partridge was00 policy director at the Center for Energy and Environment. Before joining CEE in 2017, she spent five years at CenterPoint Energy. Partridge is replacing Valerie Means, who did not apply for reappointment. 

More: The Minnesota Star Tribune 

MISSOURI 

Utilities Push Legislation to Charge Customers Upfront to Build Gas Plants

Evergy and Ameren asked the House Utilities Committee to support legislation that would allow them to charge customers for natural gas power plants before they’re completed. 

The utilities say the state is losing out on attracting major employers because it doesn’t have enough power supply. However, environmental and consumer advocates say the legislation, known as “construction work in progress,” just allows more profit for monopoly companies at the expense of consumers.  

More: Missouri Independent 

NORTH CAROLINA

Gov. Stein Announces Interim Utilities Commission Appointments

Gov. Josh Stein appointed Commissioner Floyd McKissick Jr. as chair of the Utilities Commission. McKissick will replace Chair Charlotte Mitchell, who resigned, and carry out the remainder of her term through June 2029. He has served on the commission since 2019.  

Stein also appointed Steve Levitas, a solar industry veteran and expert on energy policy, to fill McKissick’s seat. Levitas will serve through this June. 

More: Office of the Governor 

OKLAHOMA 

AG Files 3rd Lawsuit over 2021 Winter Storm Utility Rates

Attorney General Gentner Drummond filed a lawsuit on Jan. 9 in Osage County alleging artificially inflated natural gas prices during Winter Storm Uri in February 2021. 

Drummond initially filed two lawsuits last April. The lawsuits claimed the state’s gas companies violated the Oklahoma Antitrust Reform Act, the Oklahoma Common Carrier statute, breach of contract, unjust enrichment, fraud, constructive fraud, bad faith breach of contract, civil conspiracy and negligence with their actions during the storm. Drummond claims some companies had counted on higher demand with the arrival of the storm and schemed to artificially reduce supply. 

As of Jan. 24, court records show no new filings in the case, and no actions are currently scheduled. 

More: The Oklahoman 

SOUTH DAKOTA

Eminent Domain Ban Passes House, Heads to Senate

The House of Representatives voted 49–19 to advance a bill that would ban the use of eminent domain for carbon dioxide pipelines. Summit Carbon Solutions, who is vying to build a $9 billion CO2 pipeline through the state, has voluntary easement agreements with some landowners to cross their land but needs eminent domain to gain access from those who are unwilling to sign easements. The bill now heads to the Senate. 

More: South Dakota Searchlight 

TEXAS 

Xcel Energy Amarillo Coal Plant to Switch to Natural Gas

Xcel Energy’s Harrington Station, which opened its first unit in 1976 in Amarillo, will burn primarily locally produced natural gas beginning in May. Xcel said it looked into other alternatives to reduce sulfur dioxide emissions, but shifting to natural gas was the most efficient option due to the aging units and costs. 

More: Amarillo Globe-News 

VERMONT 

State Enacts EV Registration Fee

The state’s Department of Motor Vehicles has notified drivers they will have to pay $178 a year to register their EVs beginning Jan. 1. The fee is said to be twice as much as owners of internal combustion engine vehicles. At least 39 states charge such annual fees. 

More: The New York Times 

VIRGINIA 

Lawmakers’ Proposal to ‘Significantly’ Cut Appalachian Power Bills Moves Forward

A House of Delegates subcommittee voted 9-0 to advance a bill that lawmakers say would lower Appalachian Power customers’ bills by “substantially” cutting the utility’s profits and “significantly” reducing its rates. 

The bill would require regulators to evaluate Appalachian’s rates more often, prohibit rate increases from taking effect during the winter, and create a financing mechanism to shield customers from bearing the costs associated with storm-related repairs and power generation facilities. The average Appalachian residential bill has risen about $50 in the last three years. 

The legislation now heads to the full House Labor and Commerce committee. 

More: Cardinal News 

Possum Point Power Plant to Expand, Modernize for Data Centers

Dominion Energy announced it will expand its Possum Point Power Station to meet rapidly ascending data center power needs. 

Dominion will add 44 MW to the 660-MW facility via modernized gas and steam turbines. 

The plant stopped burning coal in 2003 and has since burned oil and natural gas. 

More: InsideNoVa.com 

WYOMING 

Lawmakers Kill Bill to Store Nuclear Waste

The House Minerals, Business and Economic Development Committee denied a bill that would have created a temporary nuclear waste storage facility. 

Several lawmakers were not convinced  the “temporary” storage facility would be temporary. They noted the federal government has tried and failed for decades to establish a permanent nuclear waste repository that would give some legitimacy to the “temporary” storage concept. 

More: WyoFile 

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Company Briefs

GE Vernova to Build Utility-scale Inverters at US Plant

GE Vernova announced plans to manufacture utility-scale inverters at a facility in Pittsburgh. 

GE debuted the 2,000-V DC inverter last September in a multi-megawatt solar park as part of a pilot installation in North America, which is expected to be operational early this year. The facility will start production with its 1,500-V DC model, although the manufacturing line is ready to accommodate both its 1,500-V DC and its 2,000-V DC models. 

The investment is part of a broader investment of more than $560 million the company plans to infuse into its U.S. operations over the next two years. 

More: pv magazine 

KORE Power Abandons Planned $1B Battery Plant

KORE Power has announced it is abandoning plans for a $1 billion lithium-ion battery plant in Arizona. The decision, which was attributed to the company “restructuring,” comes more than two years after KORE broke ground on the facility. 

More: Arizona Republic 

Vesper Energy Completes 600-MW Texas Solar Project

Vesper Energy has announced it has completed its 600-MW Hornet Solar project in Texas. The project is composed of more than 1.36 million PV panels on 6 square miles of land. It remains on track to be operational by spring. 

More: Vesper Energy 

Microsoft, Chestnut Carbon Reach Removal Credit Deal

Chestnut Carbon, a nature-based carbon removal company, has agreed to a 25-year deal with Microsoft to provide the tech giant with removal credits from its projects in Arkansas, Texas and Louisiana. 

The deal, the financials of which were not publicly disclosed, would deliver more than 7 million tons of carbon removal credits to Microsoft. It involves the restoration of 60,000 acres of land by planting more than 35 million native, biodiverse hardwood and softwood trees. 

More: Axios 

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Federal Briefs

TVA Names Rice CFO

The Tennessee Valley Authority has named Tom Rice as its chief financial officer, effective Jan. 27. Rice joined TVA in 2002 and has served in a variety of leadership roles, including senior vice president for finance, treasurer and chief risk officer, and vice president of financial operations and performance. Rice will succeed John Thomas, who announced his intent to retire in December. 

More: TVA 

USDA Ordered to Scrub Climate Change from Websites

Agriculture Department employees have been ordered to delete landing pages discussing climate change across agency websites and document climate change references for further review, according to an internal email obtained by POLITICO. 

The email calls on website managers to “Identify and archive or unpublish any landing pages focused on climate change” and “Identify all web content related to climate change and document it in a spreadsheet” for the office to review. 

More: POLITICO 

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NJ Abandons 4th OSW Solicitation

New Jersey’s Board of Public Utilities (BPU) on Feb. 3 shut down its fourth offshore wind solicitation (OSW) after two bidders withdrew their proposals and a third — Atlantic Shores — lost Shell as a project partner. 

The agency concluded that making an award “would not be a responsible decision at this time,” BPU President Christine Guhl-Sadovy said in statement, offering several reasons, including Shell’s withdrawal as an equity partner in Atlantic Shores and from the U.S. clean energy market.  

The BPU also cited the “uncertainty” in the clean energy market “driven by federal actions and permitting.” 

Atlantic Shores, the state’s most advanced OSW project, had submitted a proposal for the fourth solicitation that included a rebid of its 1,510-MW project approved by the BPU in July 2021, and added a second phase that would have taken the total project size to 2,800 MW if approved. 

The board made its decision “despite the manifold benefits the industry offers to the state,” Guhl-Sadovy said. 

Gov. Phil Murphy (D) called offshore wind a “once-in-a-generation opportunity” to build a new industry and create jobs, but said he supported the BPU’s decision.

“The offshore wind industry is currently facing significant challenges, and now is the time for patience and prudence,” he said. “I hope the Trump administration will partner with New Jersey to lower costs for consumers, promote energy security, and create good-paying construction and manufacturing jobs.” 

Community Offshore Wind, one of the two projects that withdrew from the fourth solicitation, said it did so after “careful consideration” because market conditions would not allow the company to meet its goal to “deliver energy projects that help address rising energy demand while meeting the development commitments established by state procurement processes.” 

“Given market uncertainty at this time, we could no longer commit to the development timelines under the framework of the NJ4 solicitation,” Will Brunelle, a company spokesman, said.  

The second withdrawn project, Attentive Energy, a subsidiary of TotalEnergies Renewables USA, did not respond to a request for comment. 

Change of Course

The abandonment of the solicitation represents a major blow to New Jersey’s OSW sector, which state officials had aggressively backed and depicted as a major economic engine in the future, and one in which the state was a leader.  

The reverberations were felt across the country. Liz Burdock, founder and CEO of Oceantic Network, said the decision was “not surprising given political headwinds and the uncertainty across the U.S. economy driven by recent federal actions.” 

Jason Grumet, CEO of the American Clean Power Association, said the decision was a “direct consequence of the uncertainty created by the recently issued executive order” to prohibit the signing of new leases for offshore wind and to review existing leases. He said his organization hopes to work with the Trump administration to “expedite its review.” 

“The U.S. urgently needs more electricity, and offshore wind projects that have already gone through a comprehensive and rigorous permitting process are primed and ready to meet future energy demand,” he said. 

But in a sign of the shifting winds, Tim Sullivan, CEO of the New Jersey Economic Development Authority (EDA), which provided funding for much of the state’s investment in the sector, said the agency would “accelerate our strategic review of options and alternatives for the New Jersey Wind Port.” 

State officials have depicted the port, in which the state invested more than $500 million, as the only one in the nation custom-built to serve OSW projects. They said the port, which sits on the Delaware River, could service wind projects developed by states along the East Coast, generating significant economic benefits for the state. 

“We remain believers in the long-term potential of offshore wind for New Jersey, but our role as stewards of taxpayer resources requires us to evaluate all of our options,” Sullivan said. 

“While recent developments at the federal level and announcements from offshore wind developers are deeply disappointing, they were not unexpected,” he said. “We have taken a cautious approach to further development of the port since 2023, and we have worked to identify alternative uses that would maximize the economic development, job creation and financial potential of the site for the state.” 

Fossil Fuel Opposition

The sweeping reversal for the state’s OSW sector comes 15 months after it was rocked by Danish developer Ørsted’s decision to abandon its two projects planned for the state’s coast: the 1,100-MW Ocean Wind 1 — the state’s first-approved and most advanced project — and the 1,148 MW Ocean Wind 2. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) 

Ørsted’s exit left Atlantic Shores as the state’s leading OSW project, and in October, the Bureau of Ocean Energy Management (BOEM) approved the construction and operations plan for project’s two phases.  

But the withdrawal of Shell, which partnered with EDF-RE Offshore Development on Atlantic Shores, emerged Jan. 31 in the company’s fourth quarter earnings results in which it took $996 million in impairment charges “mainly relating to renewable generation assets in North America.” (See Shell Quits Atlantic Shores Offshore Wind Project in NJ.) 

Responding to Shell’s withdrawal, Atlantic Shores said it remained “committed to New Jersey and delivering the Garden State’s first offshore wind project.” The company’s release said it “intends to continue progressing New Jersey’s first offshore wind project.” 

After the BPU’s Feb. 3 announcement, Atlantic Shores’ CEO Joris Veldhoven issued a statement saying the company was “discouraged” by the BPU’s action.  

“Atlantic Shores stands ready to deliver on the promise of offshore wind to achieve American energy dominance,” he said. “Atlantic Shores Project 1 holds distinct advantages of an advanced permitting program, existing supply chain investments already putting people to work, a mature interconnection plan and a clear path to financing that made us the most competitive and deliverable project proposed in NJ4.” 

A company spokesperson said although BPU did not approve the rebid submission, the “outcome doesn’t impact the existing OREC in place for Atlantic Shores Project 1.” 

But the Sierra Club’s New Jersey chapter said it did not believe Atlantic Shores could continue without the BPU’s approval of the rebid and blamed the fossil fuel sector and the federal administration for the loss. 

“By not awarding Atlantic Shores the necessary OREC in the BPU’s fourth offshore wind solicitation, we have handed over four more years of unchecked and unchallenged profit to the fossil fuel industry,” the group’s director, Anjuli Ramos-Busot, said.  

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NY Quantifies Slow Progress Toward Renewables

The latest update on New York’s Clean Energy Standard (CES) shows a work in progress, with only 23.2% of electric load being met by renewables statewide in 2023.

This is down from 25.1% in 2022 and far short of the 70% the state has mandated itself to reach in 2030 — a goal the state has acknowledged it is likely to miss, perhaps by a wide margin.

The New York State Energy Research and Development Authority submitted its annual CES progress report to the Department of Public Service on Jan. 31 (15-E-0302). NYSERDA cited progress in 2023, including completion of nine projects totaling 628 MW of capacity and 1,754 GWh of generation. NYSERDA also said work done in 2023 set the stage for further achievements in 2024 and beyond, when significant progress is anticipated.

But 2023 also was a year of numerous setbacks, with many projects experiencing delays and contract cancellations. (See NY Rejects Inflation Adjustment for Renewable Projects.) Additionally, imports of renewable energy from adjacent control areas decreased and exports of baseline renewables increased, requiring backfill by other forms of electric generation.

The report is built on data from the New York Grid Attribution Tracking System, which shows the 2023 renewables mix in New York was heavily weighted toward decades-old hydropower facilities rather than the new wind and solar facilities the state has been promoting.

Hydro contributed 18%, solar 3.4% and wind 1.8% to the mix. That compares with 49.8% from natural gas and 21.7% from nuclear.

Nuclear is zero-emissions rather than renewable, but it is an important part of the state’s effort to cut its carbon footprint. A turning point in that effort was the retirement of the two reactors at Indian Point, in 2020 and 2021.

NYSERDA’s 2019 CES report shows nuclear providing 32.4% of the New York grid’s electricity and natural gas providing 35.7%. The agency’s progress reports in 2020 through 2022 show rapidly increasing percentages of natural gas generation as more carbon was burned to backfill for the lost nuclear.

Meanwhile, installed capacity was increasing gradually for wind and more quickly for solar; 2023 was the first year either renewable contributed more than 3% of the state’s electricity.

NYSERDA and the DPS jointly reported in July that the slow pace of progress and the anticipated rise in power demand meant New York is unlikely to meet the 70% renewables by 2030 goal mandated in the state’s landmark 2019 climate bill, the Climate Leadership and Community Protection Act. (See NY Expects to Miss 2030 Renewable Energy Target.)

Thanks to imports, coal had a larger presence than wind in New York’s grid in 2023 — even though the last coal-burning power plant within its borders closed in 2020. The latest CES update shows 3,148,694 MWh of coal-generated electricity consumed in New York in 2023, compared to 2,593,709 MWh of wind. Trash burned for electricity, another frequent target of clean energy advocates, outstripped coal at 3,295,440 MWh.

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Judge Issues Restraining Order on Trump Admin over Funding Pause

D.C. District Court Judge Loren AliKhan on Feb. 3 issued a temporary restraining order on the White House’s Office and Management and Budget from pausing all federal grants and loans, including those committed by agencies through the Inflation Reduction Act and the Infrastructure Investment and Jobs Act.

The Trump administration’s “actions appear to suffer from infirmities of a constitutional magnitude,” AliKhan wrote. “The appropriation of the government’s resources is reserved for Congress, not the Executive Branch. …

“Defendants’ actions in this case potentially run roughshod over a ‘bulwark of the Constitution’ by interfering with Congress’ appropriation of federal funds. OMB ordered a nationwide freeze on pre-existing financial commitments without considering any of the specifics of the individual loans, grants or funds. It did not indicate when that freeze would end (if it was to end at all). And it attempted to wrest the power of the purse away from the only branch of government entitled to wield it.”

The memo from OMB, issued Jan. 27, called for a review of all funding and stated that “federal agencies must temporarily pause all activities related to obligation or disbursement of all federal financial assistance, and other relevant agency activities.”

This briefly threw the federal bureaucracy into chaos, as it was unclear what exactly it applied to; state-level officials and U.S. representatives reported that constituents complained about not being to access Medicare and Medicaid.

White House spokesperson Karoline Leavitt later clarified to reporters that the memo did not apply to individual, direct assistance but rather “funding for the Green New Scam that has cost American taxpayers tens of billions of dollars. It means no more funding for transgenderism and wokeness across our federal bureaucracy and agencies. No more funding for Green New Deal social engineering policies.”

OMB rescinded the memo on Jan. 29 following a temporary injunction, issued by AliKhan just before it was due to take effect. But Leavitt said that while the administration had rescinded the memo to comply with the injunction, agencies would continue their efforts to review and possibly claw back funds not in line with the executive orders President Donald Trump issued on his first day in office, including his order on Unleashing American Energy. (See Trump Will Need More than Executive Orders for US to Meet Rising Power Demand.)

That threw many programs funded by the IRA and IIJA into limbo.

The Maryland Clean Energy Center was awarded $62 million from the IRA for the state’s Solar for All program, created primarily to deploy community solar projects to help cut utility bills for low-income and disadvantaged communities. Maryland’s grant was one of 49 state-level awards that EPA announced in April 2024.

Responding to RTO Insider on Jan. 31, EPA declined to identify any specific programs but stated that “the agency has paused all funding actions related to the Inflation Reduction Act and the Infrastructure Investment and Jobs Act at this time.”

“As evidenced by the White House press secretary’s statements, OMB and the various agencies it communicates with appear committed to restricting federal funding,” AliKhan wrote in her order. “If defendants retracted the memorandum in name only while continuing to execute its directives, it is far from ‘absolutely clear’ that the conduct is gone for good.”

The case before AliKhan was brought by several groups, led by the National Council of Nonprofits. The judge noted that “plaintiffs have provided evidence that the scope of frozen funds appears to extend far beyond the reach of the executive orders.”

“As just one example, a health center that provides medical, dental and behavioral health services to a rural community was denied access to grant funds,” she wrote. “None of the seven executive orders listed in [the OMB memo] would seem to cover such activity. At oral argument, when asked about another declarant who was receiving a grant from the National Science Foundation, defendants could not give a clear answer as to why that recipient would be denied funds pursuant to the executive orders.”

Solar, EV Chargers, Rural Renewables

Solar for All is not the only IRA-funded program on pause at MCEC. According to a spokesperson, three other program awards have been put on hold.

The center was named for a $15 million award from the IIJA-funded Charging and Fueling Infrastructure program, with the money going to install 58 EV charging stations statewide, along with workforce development efforts.

CFI is administered through the Department of Transportation and the Joint Office of Energy and Transportation. The pause means the planned charger deployment and workforce development will be on hold.

MCEC also is receiving federal funds to provide technical assistance for the Rural Energy for America Program, which provides loans and grant funding to farmers and rural small businesses to install renewable energy systems or energy-efficiency equipment and upgrades.

REAP is a Department of Agriculture program. The funding pause means potential applicants cannot get the help they need to meet the requirements for applying for REAP dollars.

The Solar for All program still is in the planning stages, the spokesperson said. But without the IRA dollars, MCEC will not be able to find state funding to move ahead and reach its program goals, which include providing lower electric bills to 10,000 Marylanders.

MCEC and other Solar for All awardees have reported they have not been able to access the program portal to submit specific funding requests.

Neither USDA nor DOE responded to repeated queries from RTO Insider on whether they have instituted a funding pause.

MISO and SPP were awarded $464 million from DOE’s Grid Resilience and Innovation Partnerships program in support of five projects in the RTOs’ Joint Targeted Interconnection Queue. GRIP is a $10.5 billion IIJA program aimed at expanding and upgrading the U.S. transmission system.

In response to a query from RTO Insider, MISO replied only that it is “continuing to coordinate with the project partners on meeting the grant award requirements.”

The MISO-SPP award was one of 58 projects that received $3.46 billion in GRIP dollars in October 2023. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)

DOE’s Office of Clean Energy Demonstrations has canceled an in-person community meeting to discuss potential environmental impacts of the Appalachian Hydrogen Hub, one of seven regional hydrogen hubs funded with $7 billion from the IIJA.

The meeting was scheduled for Feb. 5 in Washington, Pa. In the email announcement, no reason was given for the cancellation, nor was information included on a potential rescheduling.

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CPUC Approves Rules to Streamline New Transmission

California regulators have approved rules to streamline permitting of transmission projects, saying the move is needed to maintain grid reliability and reach state climate goals. 

The California Public Utilities Commission on Jan. 30 approved an update to its General Order 131-D, which pertains to permitting of transmission and distribution lines, generating facilities and substations. 

The decision will speed up transmission project permitting while maintaining environmental safeguards, Commissioner John Reynolds said in a statement. 

“Building a clean energy future requires getting renewable power to where it’s needed most,” he said. “We can’t meet our climate goals without significantly expanding our transmission infrastructure.” 

The revised general order, now known as GO 131-E, takes a multipronged approach to permit streamlining. 

Transmission developers now must meet with CPUC staff at least six months before submitting an application — a step that will “better prepare applicants and help the review process run more smoothly,” the CPUC said in a release. 

The order allows transmission developers to submit their own draft versions of California Environmental Quality Act (CEQA) documents with their applications. That cuts out a step in the previous set of rules, in which an applicant provided a proponent’s environmental assessment (PEA), which thenwas followed by staff preparation of an environmental document.  

The applicant’s draft version of environmental documents will undergo CPUC review. Applicants still have the option to use the PEA process. 

The revised order also includes a “rebuttable presumption” that a proposed project meets the CPUC requirement for need if CAISO already has determined the project is needed and approved it in a transmission plan. The CPUC said the change will avoid “duplicative need determinations and unnecessary alternatives analyses.” 

The rebuttable presumption provision arose from Assembly Bill 1373 of 2023. 

In addition, the CPUC plans to launch a pilot program to track CEQA review timelines and look for ways to further speed up the CEQA process for some transmission projects. 

2-Phase Proceeding

The new rules the commission approved Jan. 30 are the second phase of changes to GO 131-D aimed at streamlining the transmission project permitting process. The proceeding, which was led by Commissioner Karen Douglas, is closed. 

“These changes will accelerate permitting timelines by reducing redundancy and shifting environmental analysis earlier in the application process,” Douglas said in a statement.  

In Phase I of the proceeding, GO 131-D was modified in response to Senate Bill 529 of 2022. The bill changed the type of CPUC permit needed to expand a transmission facility from a Certificate of Public Convenience and Necessity (CPCN) to the simpler Permit to Construct (PTC). A permit exemption also may be requested. (See CPUC Works to Revamp Tx Permitting Rules.) 

In general, a CPCN is needed for transmission projects of 200 kV or more, while a PTC is required for projects of between 50 and 200 kV. 

SB 529 also allows developers to seek a PTC or exemption for transmission line extensions, upgrades or other modifications, even if the transmission line is more than 200 kV. 

The commission approved the Phase I changes in December 2023. 

Phase II of the proceeding added definitions for several of the Phase I terms, including transmission facility “expansion,” “extension” and “upgrade.” 

“Expansion” now is defined as an increase in the width, capacity or capability of an existing electrical transmission facility, which may include rewiring or reconductoring to increase capacity, increasing the load carrying capacity of existing towers, or converting a single-circuit transmission line to a double-circuit line. 

GO 131-E defines “extension” as an increase in the length of an existing transmission facility within existing transmission easements, rights-of-way or franchise agreements; or a generation tie-line (gen-tie) segment or substation loop-in. 

Pilot Program

A new CPUC pilot program will evaluate the CEQA review process for transmission projects. It will include at least one application each from Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric. 

Two projects will involve an Environmental Impact Report (EIR), and two others will use a less time-intensive Mitigated Negative Declaration process. Projects in the pilot study will be a mix of those competitively and non-competitively bid. 

Results will be reported every other year starting Dec. 1, 2026. 

Some stakeholders opposed the pilot program. PG&E and SDG&E said CPUC resources would be better spent on speeding review of projects now in the pipeline. The Center for Energy Efficiency and Renewable Technologies (CEERT) called the pilot program a step backward, saying mandatory deadlines to complete a CEQA review should be set instead. 

The commission’s decision noted that the CPUC already routinely reviews its CEQA processes and looks for ways to improve efficiency. 

“Therefore, running a pilot aligns with current commission practice,” the decision stated. “As such, it should not distract the commission from meeting its commitment to expedite the permitting of projects.”