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November 18, 2024

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Washington Home Builders, Realtors Balk at Climate Role in Local Planning

OLYMPIA, Wash. — Washington’s home construction industry and Realtors said this week they oppose a bill to make climate change a part of local governments’ land-use planning, saying it would make it difficult to build homes in the “wildlife-urban interface.”

Senate Bill 5203 would amend the Growth Management Act to require comprehensive proposals, development regulations and regional plans to support state greenhouse gas emission targets and improve resilience to climate impacts and natural hazards. A similar bill is working its way through Washington’s House.

“It would chart a course for our communities over time,” bill sponsor Sen. Liz Lovelett (D) told the Senate Local Government, Land Use and Tribal Affairs Committee Tuesday.

She added that bill would encourage density over urban sprawl, which was an intention of the GMA when it was enacted in 1990. The law sets land use designation and environmental protection requirements for all Washington counties and cities.

Josie Cummings, representing the Building Industry Association of Washington, told the committee that adding climate change to the Growth Management Act would codify wildfire risks to the point where that factor would handicap new housing. Washington has experienced an increase in wildfires, which has been largely blamed on climate change. Wildfires have frequently threatened Washington’s small towns and villages in rural areas.

“This would reduce housing,” said Bill Clarke, representing the Washington Realtors.

In contrast with the industry groups, a large majority of the public testimony and sign-in sheets favored the bill, with 1,218 signed up at the hearing in favor of the bill without testifying, while 15 signed up opposing the bill without testifying.

Nineteen of 23 people testifying Tuesday supported the bill, and two were undecided. Supporters included state agencies, environmental groups, some individual small town council members and three disabled people, who argued the cities will improve their public transit authorities if trimming emissions leads to more bus service.

John Flanagan, a senior policy adviser to Gov. Jay Inslee, said climate change should be a factor in land use decisions at all levels of government. “We cannot rely on the actions of a few. We need to be all in,” Anacortes city council member Ryan Walters said.

“It only makes sense that the [Growth Management Act] align with other state laws,” Leah Mission of Climate Solutions said. She was referring to state law requiring Washington’s carbon emissions to be trimmed by 95% by 2050.

“If we passed this 10 to 20 years ago, we wouldn’t be in this dire climate situation that we are right now,” Redmond City Council President Jessica Forsythe said.

“We need to plan for rising tides,” Adam Maxell of Audubon, Wash. said. Washington has an extensive coastline.

Some argued that if trimming emissions leads to more bus service, then the state government needs to provide money to support expanded public transit. “If you move forward, it is critical you provide funding for this as well,” said Paul Jewell, representing the Washington Association of Counties, which has not yet decided whether to support or oppose the bill.

This is the third year that this bill has worked its way through Washington’s legislature.

The House passed it in 2021, but it stalled in a Senate committee. In 2022, both the Democrat-controlled House and Senate teetered on the edge of passing the bill before Republicans in the Senate and House used parliamentary maneuvering to kill the bill on the final day of the session.

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MISO Actions During December Storm Spark Debate

MISO’s emergency declaration during the December winter storm has ignited a debate over whether the RTO should issue the alert to sustain its neighbors during extreme weather.

The grid operator in December made the emergency declaration as a wintry blast forced generation outages and higher than forecasted load in the system, pushing MISO into a three-hour maximum generation emergency to use its collection of load-modifying resources. It lifted a maximum generation warning for its South region a few hours before the evening peak. (See FERC, NERC Set Probe on Xmas Storm Blackouts.)

Jason Howard, MISO’s director of operations and risk management, said during a Reliability Subcommittee meeting Tuesday that staff and members “successfully managed through the event.”

However, he said the emergency was necessary to manage reliability while the RTO provided a “significant amount of exports” to its neighbors. Howard said staff was able to access additional capacity once they declared the emergency.

“There wasn’t a concern for capacity,” he said. “It was a matter of maintaining reliability and helping our neighbors out. [There was] no disruption of power to the MISO footprint.”

Howard said staff felt “very comfortable” with its capacity position ahead of the storm but that MISO and the industry “struggled” with forecasting an “unanticipated, drastic increase in demand. He said the gas generation fleet began depleting its supply as the system entered the evening peak on Dec. 23.

The emergency decision was ultimately necessary to “get at emergency reserve to maintain sufficiency and export upwards of 4 to 5 GW to help our neighbors,” he said, referring to SPP, the Tennessee Valley Authority, Associated Electric Cooperative, Inc., and the Southeast planning region. Howard said MISO had a responsibility to act because some of its neighbors were either facing or actively in load shed.

Director of Market Administration John Harmon said MISO was simply “assisting in an emergency,” as it would want to similarly be aided during an emergency.

Independent Market Monitor David Patton said he was still reviewing the event, adding that his initial conclusion is MISO should define what lengths it’s willing to go to in helping neighbors at the expense of its own markets.

“I will say that I totally appreciate and agree with the notion of wanting to help your neighbors, but you should be following your operating procedures,” Patton said. “The action that any RTO takes to help a neighbor can have serious financial impacts for customers.”

Stakeholders debated whether the grid operator should call on load-modifying resources to support non-firm exports. Patton said LMRs to support exports can trigger shortage pricing “that could cost millions.”

Hwikwon Ham, with the Minnesota Public Utilities Commission, pointed out that MISO’s risk assessments depend on imports from PJM and Canada to help keep the footprint afloat.

Minnesota Power’s Tom Butz said that had MISO not helped TVA during its emergency, the ramifications might have been more dire than a matter of “economic convenience.”

“This is a first for MISO,” Howard said of MISO’s status as a net exporter during the weather event. He said staff is going to have to determine its “operational philosophy” regarding emergency procedures in aiding neighboring regions.

MidAmerican Energy Co.’s Dennis Kimm argued that MISO’s issue in December wasn’t a gas supply one, but a timing problem. He said staff didn’t commit gas generators ahead of time, thus failing to provide them enough time to secure additional supplies. Kimm said gas purchases are especially challenging to procure during a holiday weekend and after 5 p.m.

Stakeholders asked whether MISO might consider clearing additional gigawatts of gas generation in the day-ahead market to serve as a buffer when extreme temperatures are forecasted.

Staff said MISO’s five-year plan includes devising methods to better manage uncertain conditions. Howard said they are working on providing its members better situational awareness so they can make more informed decisions on fuel procurement.

Howard acknowledged “issues” with sending notifications to market participants on Dec. 23 and said that the RTO is examining the communication issues to see what went wrong.

He said the winter storm’s high pressure kept MISO’s wind production high, unlike the February 2021 winter storm that brought in a low-pressure system. “These are unique differences that we have to manage that makes the planning challenging,” he said.

Staff said their first report on the storm contained only preliminary findings but promised more discussions on the system’s performance in December. The Resource Adequacy Subcommittee is planning to discuss the storm and its implications on capacity accreditation during its March meeting.

MISO issued a cold-weather alert and conservative operations instructions for its South region Dec. 22 through Dec. 26. It also declared conservative operations for its North and Central regions and two local transmission emergencies due to congestion on Dec. 23.

Staff said the South region’s warning was necessary because of a request by joint parties to the regional transmission transfer between the Midwest and South regions that MISO reduce flows across the link. Staff said they were still in discussions with the utilities to understand why the request was made.

Factoring in exports, MISO served peak demand of 111 GW on Dec. 23. Its load averaged 78 GW during December.

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MISO: Too Early to Gauge 23-24 Capacity Supply

MISO told stakeholders Tuesday that it is not yet able to make “quantifiable conclusions” about the amount of capacity available for the 2023-24 planning year after completing its first seasonal planning resource auction (PRA) in April.

“From the supply side, it’s very early in the process to begin making predictions,” Eric Thoms, senior manager of resource adequacy operations, said during a Resource Adequacy Subcommittee meeting. He said many load-modifying resources have not yet begun the registration process and some generators haven’t completed verification test capacity data.

Stakeholders asked the grid operator to publish more frequent and precise supply data before auctions are conducted, a result of a 1.2-GW shortfall across MISO Midwest in last year’s PRA. MISO leadership has said there will be more capacity shortfalls in future auctions unless members quickly bring more generation online. (See “Stakeholders Ask for Data Improvements,” MISO Promises Stakeholder Discussions on Capacity Auction Reform.)

Thoms said reserve requirements will likely look the same by the time the auction rolls around. Staff currently estimates the RTO will need 132 GW to meet summer load, 125 GW to cover the fall, 127 GW for the winter and 124 GW for the spring. MISO’s preliminary numbers show that several of its 10 local resource zones will require more reserves for non-summer seasons, a first for the footprint.

The grid operator’s 7.4% summer planning reserve margin is lower than the 8.7% margin used in last year’s PRA. Staff said the decrease was driven by switching to seasonal modeling and “changes in resource mix/performance and load factors.”

Thoms said MISO is in the process of evaluating load-serving entities’ load forecasts to find reasons behind the smaller forecasts. He said staff has yet to form a “narrative” on why system demand is expected to decline.

Monitor Revises Mitigation to Fit Seasonal Design

MISO’s Independent Market Monitor has been prepping for seasonal auction market mitigation.

IMM David Patton has created a website for market participants to request reference levels and participation exclusions for those who don’t want to offer into the auction. He said the reference level and exclusion process will be revised to account for shorter seasonal capacity periods; it will also share the penalties for accreditation suppliers that enter generation outages.

Patton said he will consider when outage penalties and diminished accreditation make it uneconomic for a resource to offer into the seasonal auction. He said he will issue exclusions when a resource’s “expected penalties and accreditation costs in future planning years is likely greater than its forgone revenues.” He said that non-exempt generator outages render auction participation worthless when they last more than 45 days of a 90-day season and exempt outages render participation worthless at longer than 75 days.  

MISO’s tariff does not allow the risk of penalties to be included in reference levels, Patton noted. He said he will not accept requests to address outage penalties in reference levels.

Patton asked market participants to submit lists by March 14 of deliverable resources they don’t intend to offer into the PRA or be included in fixed resource adequacy plans.

Stakeholders requested additional time with the monitor to better understand market mitigation under a seasonal auction construct.

When asked by stakeholders whether Patton supported MISO’s 2023 seasonal capacity auctions or thought they were rushed, he laughed and demurred from an answer.

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Washington Hydrogen Bill Praised, Panned

OLYMPIA, Wash. — The potential creation of public authorities to run hydrogen manufacturing and distribution facilities in Washington drew praise from transit authorities and criticism from the state’s business community at a hearing of the Senate Environment & Energy Committee Wednesday.

Senate Bill 5325,  sponsored by Sen. Sharon Shewmake (D), would allow the creation of “public transportation benefit areas” to boost the use of hydrogen-fueled vehicles.

The bill would allow local governments to create authorities and to seek federal funding and ask voters for a sales tax, a business-and-occupation tax, or a utility tax to produce and sell hydrogen to power vehicles.

The transit authorities from Lewis County (just south of Olympia) Pierce County (Tacoma) and Kitsap County (across Puget Sound from Seattle) supported the bill Wednesday.

But Mike Ennis, representing the Association of Washington Business, criticized the bill, saying it would give local governments a competitive advantage over private ventures.

Washington has four hydrogen facilities being built or under consideration.

The Twin Transit Authority in Lewis County expects to have a hydrogen refueling station running by the end of this year. Its first customers will be a few hydrogen-fueled buses.

The Douglas County Public Utility District is building a hydrogen manufacturing facility next to the Columbia River in central Washington that is also aiming to be operational by the end of this year. The PUD plans to buy a handful of hydrogen-fueled vehicles and will ship the bulk of its hydrogen elsewhere.

The Port of Seattle and the Kitsap County Transit Authority are also considering whether to manufacture hydrogen.

The Port of Seattle and the Douglas County PUD did not attend Wednesday’s hearing.

Washington does not have any hydrogen vehicles because there is no way to refuel them. David Warren, head of Twin Transit, said the creation of hydrogen refueling stations is handicapped by the lack of such vehicles. “It’s a classic chicken or egg” situation, he said.

Warren said Interstate Highway 5 — which stretches from Vancouver, B.C., to Seattle, Portland and Los Angeles — would be a good corridor to locate hydrogen refueling stations.

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Many Questions on NY Energy Transition Don’t Have Answers Yet

The sweeping ambition of New York state’s net-zero vision is matched by the sheer bulk of the proposed framework for the journey.

Many key details are buried within the 445-page scoping plan finalized a month ago. But other details are not there — some because they have yet to be worked out; others because the necessary technology has yet to be perfected.

The Alliance for Clean Energy New York (ACE NY) hosted a well attended online information session on the subject Wednesday and expects to host several more.

ACE NY Executive Director Anne Reynolds was a member of the Climate Action Council, the 22-member body that drew up the Scoping Plan over three years and sent it to the legislature and governor on Dec. 19. (See New York Climate Scoping Plan OK’d.)

She served as moderator of Wednesday’s webinar and introduced it by noting that its title — “What’s In the Plan?” — was not particularly creative or snappy.

“But it is a question that I have been getting a lot lately,” she said.

New York’s goals under the Climate Leadership and Community Protection Act of 2019 are familiar by now: 70% renewable energy by 2030; 100% zero-emissions electricity by 2040; and an 85% reduction in greenhouse gas emissions from 1990 levels by 2050.

ACE NY is both an advocate for these changes and a representative for the organizations and businesses that will make them happen, and in some cases profit from the effort.

As such, they have a keen interest in knowing how the state will move to make those changes — but significant parts of that roadmap are unknown, as they must be hammered out through New York’s often opaque political process. (See Scoping Plan ‘Sets Course’ for NY Climate Goals, Raises Questions.)

That is a secondary purpose for the information sessions, Reynolds said: Keeping the Scoping Plan in the public eye and moving it forward, now that the part-time New York State Legislature is back in the Capitol.

“We wanted to do this early in the legislative session specifically so that action in the legislature on climate would be informed by this climate Scoping Plan,” she said.

Panelists from the New York State Energy Research and Development Authority and New York Department of Public Service each gave summary presentations on aspects of the plan, then opened the air to questions, such as, where does nuclear power fit into the plan?

Jessica Waldorf, chief of staff and director of policy implementation at DPS, said “nuclear is one of many technologies that will be considered” to reach the 2040 zero-emissions goals. “A lot of decisions” will need to be made before 2029, when recurring zero-emissions credits expire, she added.

Are there land-use policies that will reduce single-person vehicle miles traveled?

Adam Ruder, assistant director of clean transportation at NYSERDA, said that in fact, land-use patterns have a strong correlation to the carbon-intensive practice of people traveling one per vehicle. “As far as what policies we can do to encourage different land uses, that tends to be trickier because land-use decisions tend to be local decisions and not something the state can influence in many cases,” he said. But the state can use funding, financing and technical assistance to encourage municipalities to pursue “smart growth.”

After the December blizzard that dumped 4 feet of snow on Buffalo and was blamed for more than three dozen deaths there, can battery-powered emergency vehicles be trusted?

“These first electric trucks are not going to be the snowplows,” Ruder said. “We’re not there yet. The good thing is that we have time, and the technology is improving and is a lot better now than it was five or 10 years ago, and in another five or 10 years is going to be a lot better still.” Electrification must progress strategically, he said, starting with what is possible now.

Will backup heat sources be needed at homes with heat pumps during northern New York’s severe winter cold snaps or during multiday post-blizzard power outages?

Possibly, said NYSERDA senior adviser Vanessa Ulmer. Cold-climate heat pumps should meet the test in well insulated houses in most of New York, she said, but older houses and residents of the coldest parts of the state may need to discuss a backup or supplemental heat source with the contractor who installs their heat pump. For prolonged outages, some combination of on-site generation and/or storage and backup fossil heat may be the best strategy, she said. Finally, heat pump technology is likely to improve. “I think there will be multiple answers, and that’s an active area of research and development in New York state.”

How will the necessary construction of transmission lines be financed?

Waldorf said ratepayers and private investors pay for the expansions already under way, but substantially more investment is needed. “We’re hopeful that other resources such as funding coming out of the federal government will help support” the projects.

Is there a dollar estimate on the cap-and-invest system proposed in the Scoping Plan?

“We don’t have a final design yet,” said Vlad Gutman-Britten, assistant director of policy and markets at NYSERDA. Every policy in the Scoping Plan will have a robust public discussion before it is implemented, he said, so cap-and-invest will come into sharper focus through 2023. “There’s a lot more to come; there’ll be a lot of opportunities to provide input and feedback.” (See Hochul Highlights Cap and Invest in State of the State Address.)

Is there any control over the carbon footprint of electricity generated out of state and imported into the grid?

The state will look to address that by 2030 or 2040, Waldorf said.

How will the state keep the lights on when the wind doesn’t blow and the sun doesn’t shine, and the output of wind turbines and solar panels are reduced?

Gutman-Britten said such shortages will be intermittent and infrequent, as the grid is being designed to meet the state’s needs. Overall reliability, Waldorf said, “is something that we’re constantly thinking about.” DPS is balancing the increasing use of intermittent zero-emission power sources with energy storage and development of technology that does not now exist at scale. “It’s a key consideration that the state is well aware of and paying attention to on a daily basis.”

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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.”