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February 12, 2025

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North American Trade War Averted as Canada, Mexico Strike Deals

President Donald Trump has, at least temporarily, pulled back from starting a trade war with Canada and Mexico, issuing updated executive orders delaying the imposition of tariffs on both until March so additional talks on fentanyl, immigration and other trade issues can continue. 

Trump had threatened over the weekend to impose 25% tariffs on most imports from the two countries and a 10% tariff on energy imports from Canada. (See Uncertainty Remains Around Energy Tariffs amid Last-minute Deals.) 

“The challenges at our southern border are foremost in the public consciousness, but our northern border is not exempt from these issues,” Trump said in an executive order. “Criminal networks are implicated in human trafficking and smuggling operations, enabling unvetted illegal migration across our northern border. There is also a growing presence of Mexican cartels operating fentanyl and nitazene synthesis labs in Canada.” 

Both Canadian Prime Minister Justin Trudeau and Mexican President Claudia Sheinbaum Pardo struck deals with Trump on Feb. 3 that averted the tariffs for another month at least, with another pair of executive orders issued delaying them until March 4. 

“I firmly believe that collaboration is what makes this continent great, and it is what will enable our conversation to move from one about tariffs, which in my mind is a lose-lose conversation, to one about prosperity and security, which offers a win-win,” Canadian Energy and Natural Resources Minister Jonathan Wilkinson said in remarks to the Atlantic Council on Feb. 4. 

Wilkinson is a member of the current governing Liberal Party. Trudeau announced plans to step down in early January, which likely will lead to a new election in the coming months. According to the average of polls from the Canadian Broadcasting Corp., the Conservative Party is likely to return to power for the first time in 12 years. 

While Wilkinson discussed the longstanding partnership the U.S. and Canada have had, he noted that Trump’s tariff threats generated a patriotic response. 

“When all of a sudden Canada is treated more like an adversary than a partner, it did shake every Canadian, and I think you saw that in some of the patriotic expressions that came out in the aftermath of the decision to impose tariffs,” Wilkinson said. 

The movement of drugs and illegal immigration are smaller issues along the Canadian border than that of Mexico, but Wilkinson said his government is just as opposed to illegal smuggling and border crossings as the U.S. government. Canada recently announced an investment of $1 billion in border security, and Trudeau said he would appoint a “fentanyl czar” and list drug cartels as terrorists to work with the Trump administration, Wilkinson said. 

“Our respective economies are so integrated that I would say the partnership is effectively hard-wired,” Wilkinson said. “Nearly $2.7 billion worth of goods and services cross the border each day in 2023. Thirty-six U.S. states rely on Canada as their No. 1 export market. Canadian consumers and businesses purchased more goods from the United States than China, Japan and Germany combined.” 

The two economies are so intertwined that in the auto industry, parts will go back and forth across the border half a dozen times or more before a product is completed, he added. 

“But there is no area where the integrated nature of our economies is clearer than in energy and key resources, such as critical minerals,” Wilkinson said. “For example, Canada supplies significant quantities of low-cost hydroelectricity to several U.S. states via fixed transmission lines. Canadian electricity powers the equivalent of 6 million American homes.” 

In general, Canadian provinces are more economically linked, with energy and other sectors, to their neighboring U.S. states than they are to each other, Brattle Group Principal Johannes Pfeifenberger said in an interview. 

“British Columbia and Quebec, in particular, have vast amount of hydropower and hydro storage,” Pfeifenberger said. “So, in some ways, British Columbia would be the ideal battery for the West, and Quebec would be the ideal battery for the Northeast.” 

Excess renewables from the U.S. could be shipped up to Canada when that makes sense, and then the Canadian firms would sell it back south when American power demand is higher, he added. 

Wilkinson ran off other beneficial trading arrangements, from U.S. farmers importing potash, to the two countries working together on uranium supply so that the next generation of small modular reactors does not need to rely on supplies from more antagonistic countries like Russia. 

“I am suggesting that we should instead build upon current success by developing a U.S.-Canada alliance in energy and minerals,” he said. “Such an alliance would enable the United States and Canada to achieve our shared vision for affordable energy bills for families, strong and secure economies and North America as the world’s dominant energy supplier.” 

Electricity trading is a bigger deal between Canada and the U.S. than is trade with Mexico, where a few connections with Arizona, California and Texas are smaller and used less often, Pfefeinberger said. 

Kinetic Movement of Flowing Water

It is unclear whether trades in electricity will be covered by the laws that Trump’s executive orders cite, but he did single out electric generation and its fuels, including “the kinetic movement of flowing water,” in the order declaring a National Energy Emergency. The order imposing a 10% tariff on Canadian energy cited the energy emergency order. (See What is and isn’t in Trump’s National Energy Emergency Order.) 

Energy economist Robert McCullough, who has worked around hydroelectricity issues for decades, has an archive with 150 million files from the industry. None of them referenced the “kinetic movement of flowing water,” he said. A Google search of the phrase returns an “Energy 101” explainer video that the Department of Energy posted almost two years ago. 

“I think what we’re seeing is a bluff, and that this will fade away,” McCullough said. “But we do know that if it’s serious, they certainly didn’t prepare the paperwork seriously. The kindest word for it is that it’s ‘muddled.’ Now we are going to see a Federal Register notice, and hopefully that’ll be more operational.” 

If the talks for the next month or more between Canada and the U.S. are serious, there is plenty on electricity markets that the two sides could work to improve, he added. 

The Columbia River Treaty, which has been in effect since the 1960s, could benefit from some updates, McCullough said. While British Columbia, Ontario and Quebec are well plugged into the U.S. grid, other provinces are not. 

“Manitoba Hydro has always been isolated and confused and has never actually had the involvement in the energy markets that BC Hydro has,” McCullough said. 

On the East Coast, Newfoundland effectively has been blocked from shipping its hydropower to the U.S. by Hydro-Quebec. McCullough said that even FERC could weigh in there. Hydro-Quebec had to agree to FERC regulations, such as Order 888, when it entered into the U.S. markets. 

“Theoretically, Hydro-Quebec has signed on to 888 and has to open it up for open access, but practically, that never happens,” McCullough said. “And obviously they could go to FERC and demand that FERC penalize Hydro-Quebec and Canada for violating 888, but that apparently has never been seriously considered.” 

Normally it would be a hard case to make that a foreign, provincially owned corporation could be dinged for not following FERC’s rules on its Canadian grid, he added. But with Trump in the White House, who knows? 

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PJM Network Upgrades Boost Cost of Dominion OSW Project 9%

Dominion Energy reported that its Coastal Virginia Offshore Wind project will cost 9% more than initially expected, thanks to higher-than-expected PJM network upgrade costs.

In an update issued Feb. 3, the utility said the largest offshore wind project in the U.S. otherwise is roughly in line with the budget submitted 39 months ago. It is 50% complete and still on track to be commissioned in late 2026.

The project is in a very different situation than most other wind projects off the Northeast coast, which have suffered a litany of delays, cost increases, offtake contract cancellations, pauses on development or even outright cancellations in the past two years.

And as a fully permitted project already under construction, Coastal Virginia Offshore Wind (CVOW) also is not immediately affected by the freeze on offshore wind leasing ordered by President Trump.

In its update, Dominion indicated there were decreases in offshore construction and equipment costs because of currency hedging as well as some increases such as unexploded ordnance removal, undersea cable protection enhancements and transportation fuel.

But these were far eclipsed by the onshore network upgrades and electrical interconnection cost increases.

In its quarterly report submitted Feb. 3 to the Virginia State Corporation Commission (PUR-2024-0026), Dominion said the increase stemmed from the Phase II Study results for Transition Cycle 1 that PJM published in late December.

Based on its conversations with PJM, Dominion expects the network and interconnection costs to be $882 million higher than in the original budget estimate submitted to the SCC in November 2021. The offshore adjustments are expected to raise the price tag by $30 million.

That boosts CVOW’s anticipated total cost from $9.8 billion to $10.7 billion. Part of this will be borne by ratepayers, and part by Dominion and its partner, Stonepeak.

The levelized cost of energy now is projected to be $62/MWh, once $29/MWh in renewable energy credits are factored in. That translates to an expected net impact over project lifetime of $1.01/month for a residential customer using 1,000 kWh/month.

This compares with an average all-in development cost of $150/MWh and a residential ratepayer impact of $2.02/month for Empire Wind and Sunrise Wind, the two mature projects awarded contracts by New York state in 2024.

Empire and Sunrise are among the few offshore wind projects on the East Coast still on track; most others have been canceled, paused or are far off in the future.

Transition pieces for the Coastal Virginia Offshore Wind project are loaded on the MS Sunrise in January in Aalborg Port in Denmark. | CS Wind Offshore

What makes CVOW different beyond its sheer size — 2.6 GW, which is 50% more than Empire and Sunrise combined — is that it is being developed by a regulated utility with a regulated return on its investment.

Importantly, Dominion locked in its costs for components and contractors before supply chain constraints, inflation and interest rate hikes wreaked havoc on an industry just starting to gain momentum in the U.S. market.

Dominion is optimistic CVOW’s value proposition will carry it through the latest challenge: election of a president with a longstanding antipathy toward wind turbines, particularly the 800-foot ocean variety.

Trump’s Day 1 executive order freezing new leases does not immediately affect projects that already hold leases — except by creating an uncertainty that can scare away investors who already were looking at a long and uncertain path for cost recovery during the supportive years of the Biden administration.

The order directed “a comprehensive review of the ecological, economic and environmental necessity of terminating or amending any existing wind energy leases, identifying any legal bases for such removal.”

Dominion told RTO Insider in late 2024 that CVOW has enjoyed bipartisan support through multiple state and federal administrations in its yearslong progression from concept to plan to two-turbine pilot project to full-scale steel in the water.

“Bipartisan leaders agree it has been an economic boom for Virginia, creating thousands of jobs and stimulating billions in economic growth, while providing consumers with reliable and affordable energy,” a spokesperson said in December. “Leaders from both parties also agree on the importance of American energy dominance, maintaining our technological superiority and creating good-paying jobs for Americans.”

In its Feb. 3 update, Dominion repeated this message and noted CVOW will advance one of Trump’s stated priorities — dominance in artificial intelligence — by helping power the world’s largest concentration of data centers.

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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 FERC’s 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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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.” 

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Senate Confirms Trump’s Energy, Interior Secretaries

The U.S. Senate on Feb. 3 voted to confirm President Donald Trump’s nominee to be secretary of energy, Chris Wright, 59-38, days after confirming Doug Burgum as secretary of the interior.

Senate Energy and Natural Resources Committee Chair Mike Lee (R-Utah) said Wright, CEO of Liberty Energy, would reverse the climate policies championed by the Biden administration’s Department of Energy.

“For the last four years, when Americans opened their energy bills, they didn’t see ‘climate plans’; they saw costs piling up and questions they couldn’t answer,” Lee said. “With Chris Wright as secretary of energy, I am confident that we can reverse the irresponsible policies of the Biden administration and prioritize affordable and reliable energy.”

Lee’s counterpart in the House, Energy and Commerce Committee Chair Brett Guthrie (R-Ky.), also welcomed Wright’s confirmation.

“Maintaining affordable and reliable energy will be key to both our economic success and national security in the years ahead,” Guthrie said. “Secretary Wright understands the importance of utilizing our domestic energy resources to secure the grid, lower prices and create family-sustaining jobs.”

Burgum, former governor of North Dakota, was confirmed 78-19 on Jan. 30. Both he and Wright cleared the floor within two weeks of making it out of the Energy and Natural Resources Committee, which approved them both Jan. 23. (See Trump Energy, Interior Cabinet Picks Easily Pass Committee Votes.)

“Gov. Burgum’s confirmation today is a win for our public lands and a win for American energy,” Lee said. “He has spent his career bringing people together to solve problems and earned the trust of tribes, businesses, conservationists and working families alike. He understands that we cannot regulate our way into prosperity.”

Advanced Energy United welcomed the two new secretaries with statements arguing that its members’ technologies — such as solar, wind, storage and advanced transmission — are part of an affordable, reliable grid.

“Our industry shares with Secretaries Burgum and Wright their ambition to lower energy costs, strengthen the electric grid and make America energy abundant,” CEO Heather O’Neill said. “We urge the incoming administration to embrace and enable the market forces and investments that are allowing states to leverage advanced energy solutions to meet their energy needs. Advanced energy technologies provided 96% of all new electricity added to America’s power grid in 2024 and remain the lowest-cost way to reliably meet growing electricity demand.”

Electric Power Supply Association CEO Todd Snitchler argued that Wright and Burgum should support competitive markets as the power industry seeks to meet higher demand from data centers.

“Properly functioning competitive wholesale electricity markets have a proven track record of delivering the reliable power needed to fuel this growth while adapting to new technologies and market conditions and shielding consumers and taxpayers from investment risks,” Snitchler said. “These benefits are made all the more salient as recent news about DeepSeek and other AI tools has underscored the likely quickly changing dynamics of the industry as it develops.”

American Clean Power CEO Jason Grumet congratulated Burgum on his new role and said the clean energy industry wanted to work with the new administration.

“We are eager to support the administration’s efforts to make American energy dominance a reality,” Grumet said. “This whole-of-government approach will be crucial to aligning agencies to advance an ‘all-of-the-above’ energy strategy which is essential to achieving these goals.”

National Rural Electric Cooperative Association CEO Jim Matheson said his members often have to deal with Interior, as they operate on federal lands.

“Electric cooperatives serve 56% of the nation’s landmass and operate on more public lands than any other type of utility,” Matheson said. “We look forward to partnering with Secretary Burgum and his team to alleviate the layers of bureaucratic red tape in our land and species management agencies that so often stand in the way of electric system operations, reliability and affordability. By doing so, cooperatives can more effectively operate and maintain their systems, harden the electric grid against wildfire and other threats and meet surging electricity demand.”