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November 7, 2024

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Parties Protest PG&E Plan to Spin off Generation

Pacific Gas and Electric (NYSE:PCG) is getting pushback on its proposal to place most of its generation fleet into a new company and to sell nearly half of the firm to investors after seeking FERC approval for the plan last month (EC23-38).

“Pacific Gas and Electric Co. submits this application requesting commission authorization for a proposed transaction whereby PG&E will transfer substantially all of its non-nuclear generation assets to its new wholly owned subsidiary, Pacific Generation LLC, which jointly with PG&E will provide cost-based generation service to retail customers within PG&E’s existing service territory,” the utility said in its Dec. 13 application to FERC. “The transaction will facilitate a subsequent sale of up to 49.9% of the equity interests in Pacific Generation to one or more third-party investors.”

PG&E valued the assets — 5.6 GW of hydroelectric dams, solar arrays, natural gas plants and utility-scale battery installations — at $3.5 billion. The facilities include its 182.5-MW Elkhorn Battery project, one of world’s largest battery arrays, and the 1,212-MW Helms Pumped Storage Project, considered an engineering breakthrough when it came online in 1984.

Once PG&E transfers the generation fleet to Pacific Generation, it intends to issue a long-term debt of up to $2.1 billion on the assets to refinance existing debt.

The company contended the transaction will “strengthen PG&E’s financial condition; allow PG&E to more efficiently access equity capital to fund significant capital requirements to improve the safety and reliability of its system; and be consistent with PG&E’s path to an investment-grade credit rating.”

Its stock and credit rating plunged following a series of catastrophic wildfires in 2017-2018 and its filing for bankruptcy reorganization in January 2019. The utility’s stock has recovered some of its former value, hovering in the $15 to $16 range since October, but it remains far below its peak of more than $70/share in August 2017.

PG&E requested expedited FERC approval by March 1 because it intends to initiate its sale to investors before the end of the first quarter.

The utility filed a similar application with the California Public Utilities Commission (CPUC) in September, also seeking expedited review.

Both applications earned protests from cities, consumer groups, community choice aggregators and the Transmission Agency of Northern California (TANC), which serves publicly owned utilities. Most of the protesters urged FERC and the CPUC to slow down the approval process to gather more information and assess whether the plan is in the public interest.

“As transmission customers, TANC and its members that require PG&E or CAISO grid transmission are concerned that the proceeds from the proposed sale will not benefit PG&E transmission customers,” the agency wrote.

It urged FERC to find PG&E’s application deficient and require the utility to explain how it valued its generation assets at $3.5 billion and decided that Pacific Generation could take on $2.1 billion in long-term debt.

Public Citizen, a consumer advocacy group, told FERC that PG&E shouldn’t be allowed to monetize its ratepayer- funded generation fleet after causing a series of catastrophic wildfires.

“PG&E justifies using consumer-funded assets as a mechanism to raise assets because of financial pressures stemming from the company’s 2019 bankruptcy (from which it emerged in 2020),” the group said. “But PG&E’s financial challenges stem not from bad luck, but from the corporation’s repeated criminal negligence.”

The company was convicted of violations related to the 2010 San Bruno gas pipeline explosion that killed eight people and pleaded guilty to 84 counts of involuntary manslaughter for its role in starting the 2018 Camp Fire, which destroyed the town of Paradise.

“Consumers should not bear risk because of PG&E’s repeated criminal malfeasance,” it said.

In addition, Public Citizen said the utility had “failed to provide documentation and analysis necessary for the commission to determine if such a proposed transaction will result in just and reasonable rates, or will harm consumers.”

“As a publicly traded company, PG&E has a number of other less disruptive means to raise capital,” it said. “To ensure conformity to just and reasonable rates, the commission should require PG&E to provide analyses of alternative capital-raising strategies, including the impact on ratepayers of issuing more shares. PG&E’s sole proposal — selling off equity in rate-base generation — prioritizes investor benefits at the expense of risk to consumers.”

Parties expressed similar concerns before the CPUC, urging the state regulator to take more time to consider the full ramifications of PG&E’s proposal.

For instance, The Utility Reform Network (TURN) said PG&E’s application involves at least 50 issues that need to be resolved, including 42 identified by PG&E in its application. TURN highlighted eight additional issues, including whether the deal would leave PG&E and Pacific Generation too deep in debt and whether its benefits would flow to shareholders and not ratepayers.

“The resolution of many of those issues requires complex financial modeling to demonstrate whether PG&E’s asserted financial outcomes are likely to be realized, or whether PG&E’s proposal introduces additional financial risks,” TURN said. “The consideration of these serious implications should not be glossed over for potential shareholder benefits. …

“As part of its application, PG&E requests an expedited schedule and claims that the request is justified because there is a ‘need to resolve a financial matter expeditiously to avoid ratepayer harm,’” the group said. “As an initial matter, the only ‘financial matter’ here is one that is being created by PG&E itself, not by external forces or circumstances.”

It asked the CPUC to extend its briefing schedule, postponing a decision in the matter until at least later this year.

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Pa. County Agencies Unite for 15-MW Solar Buy

A group of 15 local government agencies in Pennsylvania are pooling their purchasing power to procure more than 15 MW of solar energy.

The Centre County Solar Group — which includes municipalities, utility authorities, school boards and a state college that together operate 384 energy accounts — are in negotiations for a power purchase agreement with three of the respondents to a request for proposals issued on Sept. 13 seeking “a long-term competitive source of electricity that meets the evolving sustainability and climate action needs of each entity.”

The RFP sought a grid-scale solar energy provider that could meet the needs of all of the local government entities, who planned to collectively strike a power price that would then be signed individually to account for certain local differences.

The combined energy use of the 15 entities would be about 32 million kWh a year, a size that, if handled by a single project, could be met by a solar project of about 15 to 20 MW that would cover more than 125 acres of land, according to Peter Buck, vice chair of the group.

The RFP amounts to the group saying: “Dear market, both retail suppliers and developers, do you have a project that would supply most or all of that? Show us what you got,” Buck said.

Three solar developers and an energy retailer responded, outlining nine solar project options with agreement term options of between 15 and 25 years, according to an update delivered in December to the State College Area School District’s board of directors, of which Buck is a member. The 6,800-student school district, which serves the borough of State College and several surrounding townships, is one of the main organizers of the effort and accounts for about 45% of the energy that the group expects to use from the project.

Buck told the board at its meeting Jan. 12 that a clean energy consultant representing the group, Green Sky Development Group, is in discussions with two suppliers, which he didn’t identify, that had proposed PPAs. Green Sky has “continued to engage with those two firms to get the best pricing,” Buck said.

The retailer, Direct Energy, proposed an agreement for all of the entities combined at $7,500/month, and the consultant had negotiated that down by $1,000, or about 15%, Buck said. All three of the companies are located in counties around the school district, according to Buck.

“The proposals that we have now are still really, really favorable,” Buck said, adding that he expects to have a finished proposal ready for the next board meeting Jan. 23.

The group in December said its goal was to get the approval of individual participating entities by late January or early February. The target date to start installation is between Fall 2024 and June 2026.

“There are a whole bunch of reasons for that” lack of a precise date, Buck said in December, citing the vagaries of the land planning process and the indeterminate ability of projects to connect to the grid. “Those are things well out of our of our control.”

Reaping Economies of Scale

Pennsylvania’s Solar Future Plan, published in November 2018, set a target of 11 GW of solar energy to be generated in 2030, by which time solar projects should provide 10% of the state’s electricity. The state is lagging behind its goal, with solar providing less than 1% of the state’s electricity, according to the Pennsylvania Department of Environmental Protection (DEP). Electricity generation accounts for nearly 33% of greenhouse gas emissions in Pennsylvania, the DEP says.

The outlook is improving, however. In the third quarter of 2022, the state had a total of 1,002 MW of installed solar capacity, up from 121.8 MW in 2021, according to the Solar Energy Industries Association. The organization predicted that the state would add 3,092 MW of installed capacity over the next five years. The DEP says there is 17 GW of proposed Pennsylvania projects in PJM’s interconnection queue.

Buck said the Centre County project grew in part out of his experience helping put together a 25-year renewable energy agreement struck by Pennsylvania State University with Lightsource bp for 100 million kWh of electricity annually. The agreement, under which power is supplied by three solar farms totaling 70 MW in Franklin County, was expected to save the university $600,000 in the first two years of operation. But Penn State said in the fall that it had actually saved $2.5 million as energy prices rose.

Pooling the energy needs of smaller entities into a larger customer is not unheard of, said Gregg Shively, principal of Green Sky. But it is unusual in the solar market, he said.

Large companies such as Google and Microsoft have the demand to strike renewable power contracts, but smaller entities generate far less interest, he said.

“There aren’t very many folks building small solar projects,” he said in the fall. Smaller entities on their own are “not going to be very attractive to someone that says, ‘Well, I can sell 10% of my project to you, but what about the other 90%? So if we can get big enough to take 100% of some projects, that makes it more attractive to the market.”

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BOEM Rule Updates Aim to Streamline OSW Permitting

The Bureau of Ocean Energy Management (BOEM) is in major rule-update mode, with two announcements in recent days aimed at streamlining the planning and permitting processes for offshore wind projects and more clearly splitting its duties with the Bureau of Safety and Environmental Enforcement (BSEE).

In a Notice of Proposed Rulemaking released Thursday, the agency set out eight areas for rule updates, such as eliminating unnecessary requirements for the specialized buoys used for site assessments and integrating independent, third-party verification of project plans at earlier stages in the approval process.

The proposed changes “would modernize regulations, streamline overly complex and burdensome processes, clarify ambiguous provisions and enhance compliance provisions in order to decrease costs and uncertainty associated with the deployment of offshore wind facilities,” according to the announcement. BOEM estimates that the updates could save developers as much as $1 billion over 20 years.

The second notice, released Tuesday, announced a transfer of responsibilities for workplace safety and environmental compliance from BOEM to BSEE. The Department of the Interior established both agencies in 2011 to “carry out its offshore energy management, safety and environmental oversight missions.” 

“Today’s action recognizes that the scopes of the bureaus’ roles and responsibilities have matured over the last decade and supports the department’s commitment to independent regulatory oversight and enforcement in the renewable energy program,” the announcement said.

Going forward, BSEE will oversee all aspects of project safety and environmental compliance, from evaluating and overseeing facility design, fabrication, installation and safety management systems, to assessing decommissioning plans.  

BOEM will focus on identifying and leasing areas for offshore wind development, approving plans for site assessments, construction and operations, and conducting environmental reviews required by the National Environmental Policy Act.

In the early days of offshore wind development, BOEM’s responsibilities included safety and environmental oversight, “until such time as … an increase in activity justified the transfer of those functions to BSEE,” according to a notice on the reorganization. The tipping point came in 2020, but the final hand-off of safety and environmental compliance to BSEE has only recently been completed, the notice said.

The regulatory and administrative updates are aimed at accelerating offshore wind development to reach President Biden’s goal of installing 30 GW of offshore projects by 2030. BOEM held three auctions in 2022 — in the New York Bight, off the Carolina Coast and on the Pacific Coast — for leases that could provide up to 11.5 GW of power.

Towers vs. Buoys

The BOEM’s NOPR will be published in the Federal Register in the coming days, starting a 60-day comment period.

The 364-page document spells out the proposed changes in several areas, including:

  • eliminating unnecessary requirements for the deployment of meteorological buoys;
  • increasing survey flexibility;
  • improving the project design and installation verification process;
  • establishing a public renewable energy leasing schedule;
  • modifying BOEM’s renewable energy auction regulations;
  • tailoring financial assurance requirements and instruments; and
  • clarifying safety management system regulations.

The changes are needed to update regulations that were formulated in 2009, when the offshore wind industry “was in its infancy” and BOEM had yet to be established, the NOPR says.

Under the original regulations, site assessments were done with fixed-bottom meteorological towers “pile driven into the seabed.” Today these assessments are done with “met buoys” that are less costly and have fewer environmental impacts. The buoys are “between 6 and 12 meters in length, attached to the seabed with a chain and mooring anchors,” which cause less disturbance to the seabed.

But permitting for a met buoy may require approvals from BOEM, the U.S. Army Corps of Engineers (USACE) and the Environmental Protection Agency because some buoys use backup diesel generators with emissions that are regulated under the Clean Air Act. The BOEM and USACE approval processes are similar, and BOEM is proposing eliminating its approval for met buoys, so long as they are not fixed bottom towers.

The proposed changes would cut site assessment permitting times, a pain point for project development, industry stakeholders have said.

Liz Burdock, CEO of the Business Network for Offshore Wind, said that the two announcements will establish “a reliable regulatory framework that the industry can plan around at a critical juncture for U.S. offshore wind.”

Pending a closer review of proposed updates, Josh Kaplowitz, vice president of offshore wind for the American Clean Power Association, pronounced them a “step in the right direction.”

BOEM’s regulations should be aligned “with a complex offshore wind development process [to] eliminate certain duplicative and overly burdensome requirements and ensure the long-term durability of its offshore renewable energy program,” Kaplowitz said. “Updating and enhancing BOEM’s rule-making process is critical to ensure the offshore wind industry maintains momentum in the permitting and deployment of clean energy.”

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Washington Estimates $1.5B in Cap-and-Trade Revenue Through 2024

Washington officials told a Senate panel that cap-and-trade auctions could raise almost $1.5 billion through fiscal 2024 and reiterated their contention that a new low-carbon fuel standard will raise gas taxes by about one penny per gallon.

Ecology department officials briefed the Senate Transportation Committee late Monday on the cap-and-trade law and its low-carbon fuel standard, both of which took effect Jan. 1.

Luke Martland, a cap-and-trade official for the department, said the revenue estimates are preliminary and liable to change. “It’s key to remember that we don’t know the future,” he said.

Washington has the nation’s second cap-and-trade system for industrial carbon emissions, following California. Much of Washington’s calculations are based on what it is observing in California.

Later this legislative session, the state Senate and House plan to allocate revenue from the state’s first cap-and-trade auction, set for Feb. 28.

Martland said the department estimates $484 million in cap-and-trade revenue for fiscal 2023 (July 1, 2023 to June 30, 2024) and $957 million in fiscal 2024.

Martland said the revenue from the auctions is expected to shrink over time as the number of emission allowances is reduced. He also said the calculations are less reliable as they are projected farther into the future. The department estimates $901 million in revenue for FY 2025, $730 million in FY 2026 and $592 million in FY 2027.

Emitting companies would bid on the allowances, which would be made available in batches of 1,000. The first auction will cover 6.185 million allowances, with a minimum allowed bid of $22.20 per allowance. The highest bidder would get first crack at the limited number of allowances, the second-highest bidder would get second crack, and so on. The auction ends when the last of the designated allowances is bid upon. Then all successful bidders will pay the same price per allowance as the lowest successful bid.

Sen. Curtis King, the transportation committee’s ranking Republican, questioned why the state’s latest carbon emission totals date from 2019, when the legislature is planning for 2023. He also noted that King County (which includes Seattle) has 2020 carbon emissions figures available.

Martland replied that the ecology department does not have enough staff for the labor-intensive task of obtaining more current figures. He added that the department is seeking money for the 2023-2025 budget biennium to add staff to speed up this work.

Potential recipients of cap-and-trade revenue are planting a massive number of trees along Washington’s rivers and streams to provide shade for migrating salmon. When water temperatures rise above the low 70s, the health of the fish is threatened. Another potential recipient is a proposed “tree bank” program. The proposal would address trees being cut down by developers and provide designated areas where replacement trees could be planted.

Republicans want to use some cap-and-trade money to create an Office of Puget Sound Water Quality to provide help to municipal sewage treatment plants to decrease the amount of nitrogen-laden nutrients dumped into the sound. These nutrients starve fish of the oxygen they need.

Impact of Fuels Standard

Also Monday, King challenged a statement by Joel Creswell, the ecology department’s climate policy section manager, that the new low-carbon fuel standards would raise Washington’s gas tax by one penny per gallon. King said he has heard estimates of 47 cents to 50 cents per gallon.

Creswell said he has heard the same higher estimates, but they were anecdotal and not backed by solid studies. He said the state had hired a consultant to study the matter, which led to the one-penny estimate. “We believe the information we have is credible,” Creswell said.

Washington’s low-carbon fuel standards require that carbon emissions from gasoline and diesel fuel sold in Washington be cut by 10% below 2017 levels by 2028 and by 20% by 2035. The bill excludes from the goals fuel that is exported out of state and fuel used by vessels, railroad locomotives and aircraft. The goals apply to overall vehicle emissions in the state and not to individual types of fuels. Northwestern Washington has five oil refineries.

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Washington Drought Bill Wins Backing

A bill to provide funding to deal with Washington’s droughts received strong support in a legislative hearing Friday.

The Washington Department of Ecology, the Washington Public Utility Districts Association, the Washington Water Trust, and the Washington Conservation Commission testified in favor of House Bill 1138 before the House Agriculture and Natural Resources Committee. Fifteen people signed in as supporters but did not testify.

The bill by Rep. Mike Chapman (D) would create a $2.5 million drought relief fund every state budget biennium, with the 2023-2025 biennium starting July 1. If the governor declares an official drought for part of the state, that fund would be increased up to $3 million.

The Washington Senate unanimously passed the same bill in 2022, but the legislative session expired before the House could vote on it.

When a major drought unexpectedly hit most of Washington in summer 2021, the state had to scramble to find money internally to help rural areas and small cities deal with the effects. Because the drought occurred after the 2021 legislative session had ended, no money had been set aside.

“When [the legislature] completes the budget, you cannot know the streams situation in July, August or September,” said Bill Clarke, representing the Washington Public Utility Districts Association. Washington’s legislative sessions usually end in March or April each year.

In 2021, Gov. Jay Inslee declared emergency drought conditions for roughly two-thirds of the state. The declarations triggered measures including moving water withdrawal allowances from one area to another, finding other emergency water supplies and dealing with situations when water has become scarce enough to hamper the passage of salmon up and down streams.

Inslee blamed the 2021 drought on climate change.

The bill would provide a stable pool of money for drought relief, said Ria Berns of the state ecology department.

“It will lessen a drought’s impacts on the state’s economy,” Jon Culp, of the state conservation commission, said.

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FERC Approves PSCo’s Temporary CO2 Price

FERC on Tuesday approved Public Service Company of Colorado’s (PSCo) request to use the social cost of carbon to help dispatch its generation for the next few months (ER23-158-001, et al.).

The utility has to use the price on carbon to limit the use of its highest emitting power plants under Colorado’s clean energy law. The price on carbon has to be factored into its generation dispatch until PSCo joins an “organized energy market,” which will occur April 1 when it joins SPP’s Western Energy Imbalance Service (WEIS) market.

Once in the WEIS, a price on carbon will no longer be used because the energy market does not price that externality.

The carbon price will only be applied to plants that PSCo owns or contracts with, not spot purchases. The utility told FERC that the carbon price should make more carbon-intensive generation dispatched less often, leading to natural gas and renewables being used more than they would have otherwise.

The carbon price is expected to raise PSCo’s systemwide production costs by about $8.3 million over the first three months of this year. The wholesale customers that fall under FERC regulation will wind up paying $664,000 of that, PSCo said.

FERC found the request to be just and reasonable. Including the state-determined social cost of carbon in its generation dispatch will allow PSCo to meet Colorado’s energy policies, the commission said.

Holy Cross Electric Association asked FERC to reserve the right to reopen the case if PSCo does not join the WEIS as scheduled, but the commission said the cooperative failed to explain why continuing to use the carbon price in such a situation would be unjust and unreasonable. If it does become so, Holy Cross or any other entity would be able to file a complaint at FERC and prove that, the commission said.

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NYISO Business Issues Committee Briefs: Jan. 18, 2023

CRIS Revisions Advance

The NYISO Business Issues Committee on Wednesday approved proposed tariff revisions to rules for capacity resource interconnection service (CRIS) expiration and transferring.

The revisions are intended to facilitate increased capacity deliverability headroom while lowering the cost of new entry in the capacity market.

The ISO is looking to complete relevant software upgrades by the fourth quarter. The changes would go into effect immediately after FERC approval. (See NYISO Finalizes CRIS Tariff Revisions.)

Although the proposal passed with 90.36% support, there were multiple abstentions. The Long Island Power Authority (LIPA), which called for a roll call vote, was the only stakeholder against it.

David Clarke, director of wholesale market policy at LIPA, said the utility “recognizes the value of many of the CRIS transfer and expiration proposals” but has concerns regarding the “three-year CRIS expiration rule as applied to external unforced capacity deliverability rights.”

“Recent experience has shown that the process to procure external capacity does not align well with the New York capacity market and creates significant challenges to acquire available resources from external control areas with three-year forward commitments for participation in the short-term NYISO capacity market,” Clarke said.

The proposal “places external controllable lines at a competitive disadvantage with internal resource supplies” and “does not address important issues with respect to maintaining CRIS for inter-ISO capacity sales,” he said.

The revisions go before the Management Committee on Jan. 25, and the ISO anticipates obtaining Board of Directors approval and filing with FERC before the end of the first quarter.

Winter Storm Price Impacts

Rana Mukerji, NYISO senior vice president of market structure, presented the committee with the ISO’s monthly market performance report for December, highlighting how the winter storm significantly impacted energy prices across New York. (See FERC, NERC Set Probe on Xmas Storm Blackouts.)

The storm drove up natural gas prices, causing the locational-based marginal pricing to reach an average of $110.17/MWh, more than double the $52.47/MWh seen in November 2022 and nearly 130% higher than the $47.99/MWh from December 2021.

When asked about how the storm can be viewed historically, Mukerji said it was “certainly exceptional” and that the closet comparison is the 2013/14 polar vortex.

Bouchez Named Consumer Liaison

NYISO announced that Nicole Bouchez, principal economist of market design, would be taking over the duties of consumer impact and interest liaison, replacing Tariq Niazi, who retired at the end of last year.

Bouchez has been with NYISO since 2003 and principal economist since 2011. She was also co-chair of the Integrating Public Policy Task Force, a joint group with the New York Department of Public Service that solicited stakeholder proposals on carbon pricing, in 2017-2018.

Bouchez said consumer interest is an exciting area and enables her to continue being involved in market design discussions.

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Electric Trucking, from Delivery Vans to Big Rigs, are Coming

Battery electric trucks, including over-the-road big rigs as well as smaller delivery van and box trucks, are expected to play a major role in decarbonizing the nation’s transportation sector, which accounts for 29% of all CO2 emissions.

The North American Council for Freight Efficiency (NACFE) has already demonstrated that even large Class 8 trucks traveling regular routes of up to 200 miles daily can replace diesel-powered big rigs. (See Report: Electric Heavy-duty Trucks Can Now Replace Some Diesels.)

That report, rich with details from onboard electronic monitors on 13 participating fleets in 2022, kept track of mileage driven, speed, the state of the battery charge, the amount of power provided by regenerative braking, the weather and the number of deliveries in real time. It concluded that electric fleets could deliver freight at lower costs based on the cost of diesel fuel and electricity during the testing.

And because electrics have fewer systems than modern diesels, and therefore lower maintenance costs, NACFE argued in 2022 that total cost of ownership of an electric would be lowered than that of a diesel vehicle.

This year NACFE is planning to look just as closely at eight charging depots used by trucking companies and freight divisions of some manufacturers that have switched from diesel to at least 15 electric trucks. Planning is already well underway. But the identities of the participating companies — and utilities — have not been released.

NACFE announced the project in a recent newsletter.

The in-depth look at the operation of charging depots of freight carriers and manufacturers with fleets that run 100 to 300 miles daily on prescribed routes, often called regional haulers, will run from mid-September to the end of the month.

“They are the ones that are making these decisions,” Mike Roeth, NACFE executive director, said of the switch that has begun in favor of electrics over diesels. “There is no typical depot, but it’s not uncommon for a site to have 40 or 50 trucks, maybe 100 trucks.”

And that means replacing diesel with electric take close cooperation with a company’s local utility. NACFE has been talking with some of these utilities as well, said Roeth.

“When you [are running] 75 or 100 [electrics], you are talking 4, 5 or 6 MW,” he said. “The utility needs to be heavily involved.”

He added that utilities appear to be more interested in a depot converting to a large number of electric trucks at once rather than adding a small number of electrics annually.

“There’s a lot of investment involved,” he said. “I think the utilities will actually like that because they will have more certainty that [the charging depots] are going to need the power.”

Roeth said NACFE, created initially to help trucking companies wring more efficiency out of existing diesel vehicles, has focused on battery electric systems rather than electric fuel cell trucks or high-tech diesel engines capable of burning hydrogen because battery electrics are simpler and available now.

Acknowledging that the U.S. Department of Energy has allocated more money for hydrogen in future trucking, Roeth argued that the budget does not mean the department favors hydrogen.

“The government is spending money on hydrogen because it’s a harder nut to crack. It’s a harder solution, and we’re not there yet,” he said.

“We are going to need [hydrogen fuel cell vehicles], but they are not the quick answer that people think. Our research and work shows that it is pretty clear and straightforward to electrify and go battery electric with whatever vehicle you can, and then use hydrogen where [electrification] just can’t be done. Hydrogen is going to follow electric trucks by eight or 10 years,” he said.

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Green Groups Seek to Block NY Power Plant Sale to Crypto Miner

Environmental groups on Friday appealed the New York Public Service Commission’s approval of a cryptocurrency miner’s purchase of a gas-fired power plant to the Supreme Court in Albany County.

The Clean Air Coalition of Western New York and the Sierra Club argue that the PSC did not weigh the impact of its decision on greenhouse gas emissions and disadvantaged communities.

The PSC voted Sept. 15 to allow a subsidiary of Digihost Technology to buy the 60-MW Fortistar North Tonawanda peaker plant, where the Canadian company had already begun crypto mining operations. FERC in December also signed off on the sale. (See FERC OKs Sale of NY Power Plant to Crypto Miner.)

Earthjustice filed the petition on behalf of the two environmental groups. New York’s Climate Leadership and Community Protection Act, the groups assert, allows deviation from greenhouse gas-reduction mandates only with justification — and not at all, if the deviation would disproportionately burden disadvantaged communities, such as North Tonawanda.

By ramping the Fortistar plant up from a sporadically used peaker to a continuously running crypto miner, the sale would increase emissions without justification and negatively impact nearby residents, Earthjustice argued.

The argument strikes at the Wallkill Presumption, a state policy in place since the early 1990s by which the PSC undertakes only reduced review of ownership transfers if it determines there will be no monopolistic or anticompetitive result.

The PSC said environmental concerns were beyond the scope of its initial, limited review of the proposed Fortistar sale; it could look only at whether the transaction would create an opportunity to exercise horizontal or vertical market power or create potential to harm ratepayers. There would be no such impact, six of the seven commissioners said, and therefore the PSC would not undertake an expanded review.

FERC also found no impact on horizontal or vertical competition, no adverse impact on rates, no impairment of regulation and no cross-subsidization.

Cryptocurrency mining has been under fire in New York for the carbon footprint of its huge electrical demand, and the state recently placed a two-year moratorium on permits for carbon-fueled operations. That first-in-the-nation move does not halt existing operations. (See NY Slaps Moratorium on Certain Crypto Mining Permits.)

The crypto operation at the Fortistar plant has been the target of noise and environmental complaints, although it also has supporters, as do other mining operations in the economically stagnant upstate region.

In regulatory filings, Digihost said there would be no change in the day-to-day operations after the purchase. The same company running it under contract since 2002 would continue to operate it, and it would sell whatever electricity it does not use on site on the wholesale power market.

In response to critical comments during the state review — including by Sierra Club and the Clean Air Coalition — Digihost said it intended to convert the plant to run on renewable natural gas and then hydrogen. It said this would make it entirely powered by zero-emissions sources by 2025 and thereby compliant with New York’s increasingly stringent climate protection laws.

The environmental groups are seeking to have PSC’s Sept. 15 approval vacated and for payment of court costs for bringing the action.

“The Public Service Commission can no longer ignore the impacts of its decisions, especially when they run counter to public benefit and endanger the air quality for communities already burdened with a disproportionate amount of pollution,” Roger Downs, conservation director for the Sierra Club Atlantic Chapter, said in a news release Friday. “Allowing a failing gas-fired power plant to be acquired and revived by an energy-hungry crypto mine, without considering the environmental impacts, runs counter to the intent of the climate law and the justice it seeks to advance.”

“New York’s landmark climate law means that agencies can’t ignore the climate and environmental justice consequences of their decisions,” said Dror Ladin, senior attorney at Earthjustice. “We’re calling on the court to hold agencies accountable and ensure that cryptocurrency miners don’t get a free pass to heat our planet and damage our communities.”

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BLM Launches Public Meetings for Western Solar Plan Update

WASHINGTON —The Bureau of Land Management is updating its 2012 Western Solar Plan to increase renewable energy development on public lands in the West, loosening key technical criteria for prospective projects and adding five states to the area covered by the plan.

BLM officials speaking at a public meeting at the  Interior Department on Friday said a new, expanded solar plan for the region could include Idaho, Montana, Oregon, Washington and Wyoming, along with the six states already covered by the plan: Arizona, California, Colorado, Nevada, New Mexico and Utah.

Western Solar Energy Plan (Department of the Interior) Alt FI.jpgThe BLM is proposing to expand the Western Solar Energy Plan to include Idaho, Montana, Oregon, Washington and Wyoming. | Department of the Interior

 

The 2012 plan also excludes projects from public lands with slopes greater than 5% and where solar insolation — the amount of energy that can be produced — is less than 6.5 kWh per square meter per day.

“These criteria were developed based on early limitations for the prior prevalent technology, concentrated solar, rather than the current prevalent technology, photovoltaic systems,” Leslie Hill, counselor to the director at BLM, said.  “So we’re interested in whether the BLM should continue using technology-based criteria to exclude lands from solar development. “

Such criteria are “static, inflexible.” Hill said. “So, they don’t change as technology or technological feasibility changes.”

In addition, Hill said, “the BLM has more experience evaluating potential solar development on public lands. More is known about avoiding or minimizing resource impacts from solar projects, and solar development demand has [grown] beyond the Southwest and California.”

The Washington event was the first of 12 in-person “scoping” meetings the BLM will hold in the coming weeks to gather public input on changes the agency should consider to the plan to increase solar development in the region. In addition to the D.C. meeting, in-person sessions will be held in each of the eleven states being considered in the plan.

“We’re mindful of balancing the needs of clean energy with our responsibility to manage important environmental, cultural and historic resources on our public lands,” BLM Director Tracy Stone-Manning said in opening remarks at Friday’s scoping session. “As we work through this process, BLM intends to work with states, tribes, local governments and the public.”

Based on input from these and other stakeholders, the BLM will draft a “programmatic environmental impact statement” (PEIS), which “will predominately evaluate the environmental effects of potential modifications to improve and expand the BLM’s utility-scale solar planning,” according to a December announcement in the Federal Register.

Individual projects on federal land must undergo an extensive environmental review under the National Environmental Policy Act (NEPA). Hill described a PEIS as a “broad, high-level NEPA review.”

“We won’t be analyzing specific solar energy projects,” she said. “However, the analyses in this programmatic EIS will allow for greater efficiency in preparing NEPA documentation for individual projects by reducing repetitive analysis.”

The scoping period will end on Feb. 28. BLM is planning to release a draft of the PEIS this summer, with another comment period to follow, Hill said.

41 Projects Permitted 

Beyond the need to update a 10-year-old plan, the main impetus for the new PEIS is the Biden administration’s drive to deploy more solar on public lands as part of its “all-of-government” approach to counter or slow the mounting impacts of climate change.

In his 2021 executive order on tackling the climate crisis, President Biden ordered the Interior secretary to review siting and permitting processes for renewable energy projects on public lands with the goal of increasing “renewable energy production on those lands … while ensuring robust protection of our lands, water and biodiversity.”

But even before Biden took office, the Energy Act of 2020 set a 25-GW target for renewable energy development — solar, wind and geothermal — on public lands by 2025. BLM says it has permitted 41 solar projects, 23 of which are in operation, totaling about 3.7 GW. The remaining 18 projects, totaling 5.5 GW, are classified as “pending construction.”

California leads the West, with 11 projects in operation and eight pending construction.

Under the Western Solar Plan, BLM created “solar energy zones” (SEZs) totaling 284,918 acres across the 97.9 million acres the agency classified as available for potential renewable energy development. Project development was encouraged in these areas, which were considered to have low potential for environmental or other permitting conflicts.  

More than 78 million acres were excluded from development, based on a range of environmental and other criteria, such as whether the land provides critical habitat for endangered species or includes “traditional cultural properties and Native American sacred sites.”

Another 19 million acres were labelled “variance” areas, in which solar development was allowed, based on a careful and detailed environmental review to assess for “anticipated conflicts with sensitive and high-value resources.”

Other solar energy, exclusion and variance zones have been designated in smaller regional plans, such as the Desert Renewable Energy Conservation Plan, which covers 22.5 million acres in seven counties in Southern California, and the Restoration Design Energy Project in Arizona.

The BLM is also seeking input on whether to include these smaller regional plans in the review for the PEIS.

‘Smart From the Start’

Only two people spoke at Friday’s in-person session, but they represented some of the conflicting interests BLM will need to integrate into its review.

Ben Norris, senior director of regulatory affairs for the Solar Energy Industries Association, raised three issues that would help increase solar development on federal lands, beginning with an increase in the amount of land open for new projects.

Norris supported the expansion of the Western Solar Plan into new states, but he said, “The solar industry is also concerned about the large disparity between lands available for oil and gas leasing and lands available for solar. At least 30 times as much onshore acreage is open to oil and gas as compared to solar.”

SEIA also supports the elimination of the current technical criteria for excluding land from solar development —  the 5% slope and 6.5 kWh/m2/day insolation requirements. The approval process for projects in variance areas should be streamlined, he said.

“Most solar development on BLM land occurs in these variance areas, which highlights the need to expand existing priority areas, and the current variance process can be complex, time-consuming [and] resource intensive,” Norris said. “A more efficient variance approval process with increased transparency will reduce permitting times and increase regulatory certainty.”

Nathan Marcy, senior renewable energy and wildlife policy analyst with Defenders of Wildlife, said his organization supports “well-planned” development of solar on public lands, provided it does not “worsen the biodiversity crisis through impacts to sensitive species.”

He called for BLM to use a “smart from the start” approach to renewable energy development on public lands, which first identifies “areas with sensitive resources that are not compatible with solar energy development.” All current environmental criteria for exclusion zones should be maintained and possibly expanded to “consider additional criteria, in particular regional habitat connectivity” — maintaining corridors for wildlife to move through existing habitats.

In designating new solar zones, Marcy said, “We urge the BLM to strongly consider mine lands, brownfields and other disturbed sites. We would also stress the importance of locating SEZs near transmission infrastructure as the lack of access to transmission has limited their effectiveness thus far.”