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November 5, 2024

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California Storms Alleviate Drought, Damage Grid

SACRAMENTO, Calif. — After three weeks of torrential rains and high winds from a series of atmospheric river storms, California started to dry out Tuesday, with sunny skies forecast for at least the next 10 days.

The storms that began Dec. 26 caused widespread flooding and power outages as winds toppled thousands of power poles and trees. They also refilled hydroelectric reservoirs severely depleted from three years of drought and built snowpack in the Sierra Nevada that in some areas is nearly 300% greater than normal for this time of year. The state relies on that snowpack as it melts during the dry months from May to October for hydroelectric generation, farming and residential use.

In San Francisco, which bore the brunt of the storms as they flowed in succession from the central Pacific, more than 18 inches of rain fell since Dec. 26, making it the “wettest 22-day period since January 14, 1862,” the National Weather Service said. (The prior record-holding period was known as the Great Flood of 1862, when weeks of January rains caused rivers to overflow their banks from northern Oregon to Southern California.)

In the Sacramento area, at least 599,000 customers lost power as 1,800 power lines were downed in the 10 days after New Year’s Day, the Sacramento Municipal Utility District reported. The four storms that hit during that period were the most damaging string of storms in the utility’s 100-year history, with the “largest mobilization of personnel and restoration crews ever,” SMUD said. More than 300 power poles were toppled — each of which takes a full crew eight hours to replace — and 650 trees fell or broke, SMUD said.

“Due to extensive damage, many customers have experienced lengthy outages that last overnight, and some will last several more days,” the utility said in a Jan. 10 news release. “SMUD has been contacting vulnerable customers we expect to be out of power overnight directly so they can make arrangements.”

Pacific Gas and Electric also said it mobilized its largest storm response in company history to restore power to 1.6 million customers who lost power in the first two weeks of January.

“PG&E has more than 5,000 dedicated personnel currently responding to the storm, including contractors and mutual aid from Southern California, Canada, Colorado, Idaho, New Mexico, Oregon, Utah, Washington, Wisconsin and Wyoming, with additional resources expected to arrive and assist in the coming days,” the utility said in a Jan. 9 statement. “Hundreds of PG&E employees are serving in the company’s Emergency Operations Center as well as in regional and divisional emergency centers.”

Flooding in low-lying areas and the threat of mudslides in coastal hills led to evacuations in Sacramento County and Santa Barbara County, respectively, while the Monterey Bay area was pummeled by huge waves and nearly cut off from the rest of the state by swollen creeks and rivers.

President Biden plans to visit storm ravaged areas Thursday, following his issuance of a major disaster declaration for six counties.

In addition to destruction, the storms brought badly needed precipitation to California after three years of drought that undercut hydropower, adding to the state’s summer resource shortfalls and near blackouts.

Lake Oroville, the state’s second-largest hydroelectric reservoir with more than 3,500 acre-feet of capacity, had filled to 105% of its historical average for the date Tuesday and stood at 58% of capacity. Two weeks ago, the lake held 74% of its historical average and 39% of its capacity. It had run so dry in the drought that generation ceased in July 2021 for the first time since Oroville Dam was built in the 1960s.

Eight of the other major reservoirs operated by the state Department of Water Resources (DWR) had filled to their historical averages on Tuesday after years of depletion. Seven others that remained below average included Lake Shasta, the state’s largest man-made reservoir with a capacity of 4,552 acre-feet. But the lake had refilled to 84% of its historical average and 53% of its capacity; two weeks ago, it was at 57% of its historical average and 34% capacity.

Snowpack numbers were even more impressive. After three years of nonexistent or quickly vanishing snowpack, much of the Sierra Nevada Mountain range was buried in 30 feet of snow. The Northern Sierra had 202% of the region’s historical average snowpack on Wednesday; the Central Sierra had 253%; and the Southern Sierra had 292%, DWR reported.

All three areas already had met or exceeded 100% of average snowpack for April 1, a key date in state water planning for summer. The Southern Sierra had 148% of average snowpack for April 1, and the Central Sierra had 128% of average.

On a Jan. 10, the U.S. Drought Monitor removed much of the state from “extreme” and “exceptional” drought conditions, which had persisted through December. Moderate and severe drought still grips most of California.

Whether the snowpack lasts until it’s needed in the dry months remains in question. After a wet December 2021, 2022 saw the driest January-March period on record. State water officials have warned that more storms are needed to ensure an adequate water supply this year.

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Phillips Says Transmission NOPRs Still a Priority

WASHINGTON — Acting FERC Chairman Willie Phillips on Wednesday said he would continue to prioritize the transmission initiatives his predecessor started in his first public comments since being named to run the agency at the beginning of the year.

Transmission is important to ensuring reliability and resilience, Phillips said, and they have been areas he has focused on since joining FERC in 2021. The Inflation Reduction Act should accelerate the transition towards clean energy that the industry is going through, which will also need ample new transmission.

“I’m glad to say that the transmission NOPRs [Notices of Proposed Rulemakings] and proceedings that we started last year, they’re aimed at doing just that,” Phillips said at Energy Bar Association Northeast Chapter’s Winter Summit. “As your chairman, I want to make sure that we keep the momentum going on these important transmission reform efforts.”

Phillips also made similar comments before the D.C. Public Service Commission’s Clean Energy Summit the same day.

“We’re not going to sit on our hands,” Phillips said at the PSC, where he was chair before he joined FERC. “I’ve already started to engage my colleagues, to engage them and talk about, what are the ways we can continue to move forward? I think that’s the only way to reach the administration’s goal of clean energy by 2035.”

While some have argued that building out the infrastructure needed to combat climate change is at odds with environmental justice, Phillips said, he is not one of them.

“I think with the opportunities with advanced reconductoring, in particular, where you don’t just have to build, but you can have these lines that are able to reduce the amount of energy loss and increase the amount of energy that can flow across for many, many miles, I think that there’s so many opportunities to save money,” he added.

Advanced transmission technology can reduce the need for new transmission; that not only addresses more traditional environmental justice concerns but ensures the transition is done affordably, he added.

The departure of former Chairman Richard Glick means that FERC is at a 2-2 partisan split among its four remaining commissioners, but Phillips told EBA that would not stymie its efforts. (See Glick Bids Farewell to FERC.)

“I submit to you that when it comes to doing important things, really important things, for our nation, we are not as divided as politics might suggest,” Phillips said. “I think there is a real opportunity if we approach each other as colleagues, and with respect.”

Mark Christie 2023-01-18 (RTO Insider LLC) FI.jpgFERC Commissioner Mark Christie joins remotely | © RTO Insider LLC

Republican Commissioner Mark Christie had echoed that sentiment earlier at the EBA meeting.

“I’m not a math wizard at all — I majored in history — but the magic number is still 3,” Christie said. “That’s how many votes it takes to get an order out and that hasn’t changed.”

Christie cited some statistics that Glick compiled before his last meeting in December, including that 98% of the orders under the previous chairman were voted out with four or more votes.

But Christie also conceded that there are contentious issues such as the natural gas pipeline certificate policies that the Democratic majority proposed last year over his and fellow Republican Commissioner James Danly’s objections. However, most of the work before FERC is under the Federal Power Act, he said, and he did not see any partisan splits stopping that from moving forward.

Phillips also touched on geopolitics, saying that while the people of Ukraine have obviously suffered the most under Russia’s invasion, its effects have been felt throughout the energy industry as the war scrambled global supplies and has contributed to price spikes.

Europe, many countries in which used to rely on Russian sources of energy to meet a significant amount of their demand, has seen the worst of that, with talk earlier in the year of running short on resources that require significant energy to produce, such as fertilizer and steel.

“And it was a real concern talking to my European colleagues, that that was going to impact us here,” Phillips said.

Keeping the lights on will continue to be a priority for Phillips, as he cited the need to plan for extreme weather, as seen over the holidays, and increase the security of the grid against both cyberattacks and physical attacks, especially after the recent shootings of substations in North Carolina and Washington state.

“What is clear is that we’ve had, yet again, a wakeup call,” Phillips said. “Another wakeup call that threats to our bulk power system … are real; that they require us at FERC to refocus our efforts on reliability and resilience.”

At both events, Phillips recalled his childhood in Alabama, telling EBA that being named to run FERC is the “greatest time in his career.”

“I know the impact that agencies like the D.C. Public Service Commission and the Federal Energy Regulatory Commission can have on the individual; on the family; on the community,” he said at the PSC summit. “And so, as a regulator, I think it is incumbent upon us to make sure that we do all that we can to build our power to make sure that those people from underserved communities; that they have a voice; and that we take that voice into consideration and make our decisions in a meaningful way.”

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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.