SPP said Monday it has selected Deborah Sterzing, who has more than 20 years of experience in finance and electric industry financial planning, as its new CFO. She replaces Tom Dunn, who retired in December after 21 years with the RTO. (See “CFO Dunn Retires,” SPP Board/Members Committee Briefs: Oct. 25, 2022.)
Sterzing will be responsible for developing and executing SPP’s overall financial strategy, aligning it with the RTO’s vision and objectives. She previously served as CFO of Wind Energy Transmission Texas and has also held financial roles at Citigroup, High Bridge Energy Development, Skaia Energy, Green Mountain Energy and General Electric.
“[Sterzing’s] strategic, financial and regulatory expertise will ensure SPP has the organizational readiness necessary to lead our industry to a brighter future,” SPP CEO Barbara Sugg said.
Compromise bills that will change how utility rates are regulated in Virginia sailed through both chambers of the General Assembly during the last day of its session Saturday.
The legislation, which was passed nearly unanimously, is backed by Gov. Glenn Youngkin (R) and the state’s largest utility, Dominion Energy (NYSE:D).
The legislation removes some rate riders and will set Dominion’s return on equity at 9.7%, which is about halfway between the current 9.3% and the 10.03% in an earlier version of the bill. That rate will be in effect later this year until 2025, when the State Corporation Commission will set its rates, freed from basing them on a peer group of its fellow Southern utilities that had been the practice in Virginia for more than a decade.
“I applaud the legislators who took the lead on writing and negotiating this landmark bill, which will save customers money on their monthly bills, restore the independent oversight of the State Corporation Commission and support the long-term stability of Virginia’s largest electric utility,” Youngkin said. “Today, the General Assembly came together and put Virginians first.”
Senate Majority Leader Richard Saslaw (D) | Virginia Senate
The companion bills — SB 1265, introduced by Senate Majority Leader Richard Saslaw (D), and HB 1770, introduced by Del. Terry Kilgore (R) — cleared the Senate unanimously in votes Saturday and only drew one opposing vote in the House of Delegates from Del. Dave LaRock (R).
“What we got here today, though, finally is a good, well rounded deal,” Kilgore said. “A deal that’s good first and foremost, for Virginians. And a deal that’s good for Dominion, a utility whose health that we need to deliver energy reliably.”
The bill shifts $350 million from rate adjustment clauses into the base rates and spreads $1.7 billion in fuel costs that Dominion has incurred because of recent price rises over 10 years, Saslaw told his fellow senators as they debated the bill on the floor.
“Instead of getting a $17/month increase on July 1, it won’t happen,” Saslaw said. “It’ll be pennies more to the average bill as a result of being able to spread it out like that.”
Getting rid of the rate adjustment clauses will save the average customer between $6.50 and $7/month, he added.
The bill also includes changes to Dominion’s “rate collar,” so that if the utility over-collects by more than 70 basis points on its ROE, 85% of the excess will return to customers; if it over-collects by 150 points, all of it goes back to consumers.
“We’re going to vote on a bill that was not dictated to us by Dominion Power, but rather it was people working together from different viewpoints: the ratepayer viewpoints, the power company viewpoint, the industrial consumer viewpoint, even environmentalist viewpoint,” Sen. John Chapman Petersen (D) said. “Not everybody got what they wanted. But you didn’t have one entity dominating the conversation.”
Senate Minority Leader Thomas Norment (R) pushed back on the notion that Dominion dictates the commonwealth’s electricity policies, noting that major corporations were behind the push to deregulate the electric industry more than two decades ago; years later, many of them also supported legislation stopping retail deregulation from going into effect.
How the law gets implemented is ultimately up to the SCC, but it only has one member now, and the legislature did not address the two vacancies, Sen. Scott Surovell (D) said. Currently the SCC only has Jehmal Hudson serving as a commissioner after Judith Jagdmann stepped down, and the legislature did not reappoint Angela Navarro, who had finished out Mark Christie’s term after he left to join FERC.
Surovell had introduced SB 1482, which would have added a fourth commissioner to the SCC, then eliminated that position when the next vacancy occurred, in an effort to break the logjam at the legislature.
“In order for somebody to be looking out for the little guy, we have to have a regulator that’s ready to follow through on all the discretion that’s been given under this bill,” Surovell said. “And right now, there’s only one commissioner sitting on the SCC and there’s two vacancies. And that’s not getting resolved today.”
Dominion welcomed the legislation’s passage, calling it a win for consumers and regulatory oversight.
“It will lower electricity bills for our customers, reduce the impact of rising fuel costs and strengthen SCC oversight,” a utility spokesman said in a statement. “We appreciate the leadership of the patrons, Gov. Youngkin, Attorney General [Jason] Miyares and lawmakers from both parties in getting this bipartisan legislation across the finish line.”
One of the early drivers in the effort to site floating power generation off the U.S. coast outlined a plan last week to continue its early work, enlarging its economy and shrinking its carbon footprint in the process.
The Maine Offshore Wind Roadmap is the result of 18 months’ work by 96 committee members studying the concept from every angle.
Much of the roadmap boils down to core concepts: gathering data; collaborating on plans to use the data; communicating those plans; minimizing adverse impacts and maximizing benefits of those plans; and ensuring those benefits are shared equitably.
Bringing those concepts to fruition is where the challenges and disagreements will crop up, and the roadmap seeks to prevent as many of them as possible.
Speaking to the U.S. Department of Energy’s Floating Offshore Wind Shot Summit on Thursday, after her Energy Office released the roadmap, Gov. Janet Mills cited all the groundwork Maine has done to prepare for the effort, including placement of the first test turbine in U.S. waters.
The University of Maine…s Alfond W2 Wind-Wave Ocean Engineering Laboratory is shown. | University of Maine
“Maine has the tremendous potential to become a global leader in offshore wind, and that means more good paying jobs, cleaner energy and a healthier environment,” she said. “We’ve already started the work to get us here as well.”
With its strong and sustained winds, the Gulf of Maine is considered one of the best potential U.S. sources of offshore wind energy. But it is too deep for wind turbines with rigid sea-floor foundations, so development there will rely on floating turbines, a concept still in development.
Meanwhile, a large part of Maine’s economy is linked to its oceanfront and fishing industry, which are anxious to avoid harm from placement of wind power arrays. In response, Mills in 2021 signed into law a 10-year moratorium on offshore wind development in state waters, pushing the nascent industry farther out into federal waters.
Outsized Plans
Large states such as California, New York and New Jersey have been one-upping each other with high-megawatt offshore wind goals, but small states such as Maine and Rhode Island (whose combined population is one-eighth New York’s) are also contributing to the growth of the sector.
The first few fixed-base offshore wind turbines in the U.S., in Rhode Island waters, have yielded empirical knowledge that can be incorporated into future projects, and Maine has been researching floating offshore wind (FOSW) technology for more than a decade.
The University of Maine’s Advanced Structures & Composite Center has developed VolturnUS, a semisubmersible concrete hull for FOSW applications, and hopes to commercialize it. The center’s executive director, Habib Dagher, told the FOSW summit Thursday that it shares technology with bridge construction and can be manufactured in local communities. A decade ago, the university placed a 1:8 scale test turbine off the coast at Castine.
Habib Dagher, executive director of the Advanced Structures and Composites Center at the University of Maine, poses at the Alfond W2 Wind-Wave Ocean Engineering Laboratory. | University of Maine
In 2024 the university and its partners plan to anchor a single 11-MW floating turbine near Monhegan Island. This will pave the way for a planned research array of 10 to 12 FOSW turbines, with a capacity of up to 144 MW, farther out to sea. Maine hopes to gain U.S. Bureau of Ocean Energy Management approval in 2023 for the project. (See BOEM Continues Planning Process for Maine OSW.)
The university also has reported advances in floating light detection and ranging technology, synthetic mooring lines and 3D printer fabrication of components. It has built a wind-and-wave test basin, expanded its FOSW engineering team to 45 people and added graduate student concentrations in offshore wind.
Maine is known for harsh winters, and its residents are more dependent on heating oil than any other state. The state’s decarbonization efforts and Mills’ goal of 100% clean energy by 2040 are expected to double the state’s power demand.
Against this backdrop, the state considers FOSW a source of both new energy and economic stimulus: Nearly 80 Maine firms already are engaged in or are poised to enter the offshore wind industry, and 117 occupations would be involved to some degree in a buildout, the roadmap states.
Objectives and Strategies
The roadmap and the supporting technical reports are posted on the Maine Offshore Wind Initiative website. The roadmap breaks out five broad objectives and suggests several strategies for achieving each:
boost offshore wind supply chain, infrastructure and workforce investments by creating opportunity for Maine businesses; investing in port and manufacturing infrastructure; attracting workforce; ensuring workforce opportunity and inclusivity; and developing export opportunities for businesses and research institutions.
harness renewable energy to control costs and fight climate change by establishing a FOSW procurement and coordinating it regionally for cost effectiveness; pursuing regional transmission strategies; ensuring a stable and predictable investment environment; and advocating for federal leasing mechanisms that support Maine’s goals.
advance Maine-based innovation to compete nationally and globally in offshore wind by continuing development of FOSW demonstration projects; commercializing the state’s R&D capabilities; establishing an in-state FOSW innovation hub; leveraging and expanding in-state capabilities in artificial intelligence, data science and robotics; and researching complementary technology such as energy storage and clean fuels.
support Maine’s seafood industries and coastal communities by seeking engagement and integrating technical feedback from fishers and residents; promoting open research and data-gathering; learning from information yielded by research turbines; seeking to avoid or minimize conflicts by prioritizing development outside key lobster and fishing areas; designing wind farms to ensure safe navigation; and promoting fair and equitable benefits.
protect the environment, wildlife and fisheries ecosystem in the Gulf of Maine by collecting high-quality data in cooperation with fishers, scientists and others; proactively reducing conflicts and minimizing impacts while facilitating timely permitting; strengthening Maine’s policy framework, including through the review authority conferred by the federal Coastal Zone Management Act; enhancing collaboration with other states in the gulf; continuing state funding and pursuing federal funding; facilitating open engagement and integration of technical advice; and promoting and advancing new technologies, then allowing for their integration into planning.
Texas politicians are making a last-ditch push to avoid the retirement of a 37-year-old coal plant in East Texas that they say has another 22 years of useful life.
However, there may be little they can do.
The plant in question, Southwestern Electric Power Co.’s (SWEPCO) (NASDAQ:AEP) Pirkey Plant, was scheduled for retirement in 2020 to comply with environmental regulations. The plant, a 580-MW coal-fired unit in SPP’s eastern Texas footprint, went into operation in 1985 and will cease operations in March.
In a letter to the Texas Public Utility Commission earlier this year, 13 state senators called on the commissioners to delay approving SWEPCO’s pending rate-increase request for renewable generation until they can determine whether there is a “legitimate” reason for Pirkey’s early retirement.
The lawmakers said that the analysis SWEPCO relied upon in deciding to retire the plant was “seriously outdated and … seriously flawed.” They cited testimony in the utility’s rate case docket that “called into question” the economic and environmental regulatory assumptions used to make the decision (53625).
Sen. Bryan Hughes (R), who signed the letter, chairs the State Affairs Committee that held a hearing on Pirkey last year, and his district includes the plant’s site. He made an impassioned plea for its survival during a surprise appearance at the PUC’s most recent open meeting.
He said the lawmakers’ ask of the commission was very simple: to consider their letter and intervene in the proceeding.
“We want to make sure this decision is being made in the best interest of Texas and Texas ratepayers and folks who need that electricity,” Hughes said. “These folks happen to be outside of ERCOT, but they’re inside Texas. You have much more authority outside of ERCOT as far as regulating these companies.
“Slow this process down. You have the power to do it. And if you don’t, it’ll be too late,” he added.
PUC Chair Peter Lake thanked Hughes for his attendance and “highlighting the urgency of the issue,” but he offered no other support. The commissioners did not discuss the issue during the open meeting.
Texas State Sen. Bryan Hughes makes his case before the PUC. | AdminMonitor
PUC spokesperson Ellie Breed declined to speculate on the commission’s decision. “Staff is reviewing the situation and the concerns raised by Sen. Hughes,” she said.
Hughes’ appearance before the PUC caught some by surprise.
“It kind of came out of left field. … We were all a little bit caught off guard by it coming up in a discussion about ERCOT market design,” said Katie Coleman, who represents Texas Industrial Energy Consumers, an intervenor in the SWEPCO docket. “I’m not sure who he had talked with in advance of that, but I think that the narrative around the need for dispatchable resources caught [Hughes’] attention.”
In their letter, the senators say the State Affairs hearing “uncovered evidence about the coercive ‘manage-down-to-zero’ [environmental, social and governance] practices” of American Electric Power’s top three shareholders. AEP is the parent company of SWEPCO, which also services portions of Arkansas and Louisiana. According to Bob Eccles, an ESG expert, Vanguard Group, BlackRock and State Street own a collective 20.5% of the organization.
“AEP is the picture of woke capitalism and ESG virtue-signaling to the detriment of stockholders and, in this case, ratepayers. We believe that’s exactly what’s driving this decision,” Hughes told the PUC.
AEP has been open about its plans to transition to cleaner-burning fuels. It has retired or sold nearly 13.5 GW of coal-fueled generation in the last decade and has committed to achieving net-zero emissions by 2045 and an 80% reduction relative to 2005 levels by 2030.
The Columbus, Ohio-based company said it decided to shutter Pirkey and stop burning coal at the nearby Welsh Plant to comply with EPA’s coal combustion residuals rule. AEP said its actions would save customers an estimated $740 million to $1.2 billion by avoiding compliance costs and higher ongoing operating and fuel costs.
“Pirkey’s fuel costs have been rising for more than 15 years and were expected to remain higher than other similar SWEPCO plants,” spokesman Scott Blake said in an email to RTO Insider.
He said the more than 200 employees at the two plants have since elected to retire or found work elsewhere, many within the AEP system. Pirkey’s closure will also shut down Sabine Mining’s lignite mine that fuels the plant and its 130 jobs; many of its employees have also found work elsewhere.
Blake said the company followed SPP’s notification process for retiring units. The RTO requires at least a 12-month heads-up of a unit’s pending shutdown. It does not approve or reject the retirements but does conduct a study to determine whether its absence would create a reliability issue that needs a short-term mitigation or transmission solution.
“From our perspective, AEP’s plans may continue,” said Casey Cathey, SPP director of grid asset utilization.
Energy consultant Alison Silverstein, a former PUC staffer, said SPP’s opinion “is what matters for closure,” noting that the grid operator did not consider the cost impacts to SWEPCO or its customers, or “the market impacts of having that production available.”
“The whole point of being in a regional market with adequate generation and transmission capacity and a competitive market is that a utility can buy its energy from other producers in the region, rather than just having to own all of its power plants,” Silverstein said. “SPP is highly competitive and has lots of generation and transmission. The fact that they approved the Pirkey closure means they think it’s not needed for long-term grid reliability, and presumably that replacement power from the region is deliverable into the SWEPCO footprint.”
Not surprisingly, the plant’s retirement and the loss of local jobs and tax revenue have created a regional uproar. Eccles wrote a tongue-in-cheek piece for Forbes about the State Affairs hearing and Texas’ dichotomy as a state rich in renewables, yet eager to add dispatchable (i.e., thermal) generation.
In February, Wayne Christian, a member of the Railroad Commission — which regulates Texas’ intrastate gas and petroleum industry but not railroads — keynoted the annual Republican Lincoln Day Dinner in Harrison County, where Pirkey is located.
“AEP bought the thing and decided it was going to shut it down regardless,” Christian was quoted as saying in a local newspaper. “Thirty years of this plant here in Hallsville, got 30 years in reliable generation of electricity, and we’re tearing that sucker down because it ain’t working. It doesn’t fit into the [environmental] religion.”
“I don’t blame legislators for wanting to protect the local utility, local jobs, local communities and tax base by resisting the closure of a coal plant and coal mine,” Silverstein said in an email. “The Pirkey plant … is a great source of ongoing revenue for SWEPCO, so the fact that the integrated utility wants to shut it down before the end of its useful life indicates that they are looking ahead at favorable energy replacement costs, the likely high costs of meeting upcoming EPA coal emissions requirements and potential rate base replacements.
“But this coal plant and coal mine are imposing significant costs on the communities and on all SWEPCO customers, and it appears that they could save money for everyone if they shut down the Pirkey plant and replaced it with SPP region-sourced energy alternatives,” she said, noting the Inflation Reduction Act contains “big incentives to reinvest in communities to ‘retool, repower, repurpose or replace’ fossil infrastructure and recover transition costs.”
“It’s likely that the communities these legislators represent could come out ahead in terms of jobs and utility bills within a few years if the legislators work with SWEPCO for a smart energy transition, rather than trying to protect an old coal plant,” Silverstein added.
Coleman said that SWEPCO being outside ERCOT offers a “different paradigm” and leaves the PUC with few options.
The commission’s next open meeting is March 5, leaving it little time to change AEP’s course.
DTE Energy executives warned Thursday that the utility needs to continue its investments in grid reliability and cleaner generation, investments that won’t come cheap.
CEO Jerry Norcia said during DTE’s (NYSE:DTE) year-end conference call with financial analysts that the utility didn’t request base rate increases during the COVID-19 pandemic to keep rates affordable. He said DTE now needs to reflect investments in “system reliability, grid modernization and cleaner generation.”
“Since 2020, we invested more than $8 billion in DTE electric system while keeping base rates nearly flat,” Norcia said. “After four years of essentially no base rate increases, we are requesting an increase that would go into effect at the end of 2023. This request supports investments in Michigan to improve reliability and deliver clean energy while maintaining affordable rates.”
The utility last month filed a $622 million annual rate increase with the Michigan Public Service Commission that would begin at the end of this year. The commission in 2022 reduced DTE’s request for a $388 million rate increase to $30.5 million, disputing projections of declining residential consumption. The PSC said residential use was on the upswing in 2020 and again in 2021.
“Although there were a lot of positive aspects to the outcome for which we are very grateful … we were disappointed by the projected residential sales volume in the final order,” Norcia said.
He said DTE is refreshing residential sales volume projections in the rate case. The utility also has requested an infrastructure recovery mechanism to allow it to recover the cost of grid investments between the rate cases.
“[DTE is] committed to working with all interested parties to pursue a settlement that strikes the right balance between continuing to increase reliability and providing cleaner energy for our customers, all the while maintaining affordability,” Norcia said.
CFO David Ruud said that because the PSC allowed only a modest increase, DTE will enact “one-time cost reductions that are not sustainable over the long term,” including delaying hiring, reducing the contractor workforce, deferring near-term maintenance work, and limiting overtime.
“These initiatives are all in areas where we have achieved success in the past like during the start of the pandemic, and during the last recession,” Ruud said. “[W]e remain confident that we will achieve our financial goals for the year without sacrificing safety, reliability or customer service.”
Despite the smaller-than-expected rate recovery, DTE reported earnings of $1.1 billion ($5.52/diluted share) for the year, compared to 2021’s earnings of $907 million ($4.67/diluted share).
For the quarter, earnings were $265 million ($1.31/diluted share). Earnings were $306 million ($1.57/diluted share) the year prior.
Norcia said 2022 was a record year for grid reliability and renewable energy investments, with the utility investing more than $1 billion in its grid last year to help improve reliability. He said the system operated reliably 99.9% of the time last year, with 21% fewer power outages than 2021. Average outage-duration times were reduced by more than 40%, he said.
“In communities where DTE completed some of our most focused work on a grid’s more challenged infrastructure, customers experienced up to a 70% improvement in reliability,” Norcia said. “2022 was a record year for investment in our grid, and the result was stronger reliability.”
DTE conducted the earnings call while working to restore service to about 400,000 customers after ice storms rolled through the service territory Wednesday.
Norcia said DTE needs to continue reinforcing the grid for more “violent weather” and the added strain of electric vehicle load growth.
The utility has increased its five-year capital plan by 20%, $3.5 billion more than last year’s plan, owing to “infrastructure renewal and cleaner generation,” Norcia said.
He noted that DTE in 2022 secured contracts with Ford Motor Co. and automaker Stellantis under its voluntary renewable energy program, MIGreenPower. The company said it currently has 900 businesses and 85,000 residential customers enrolled in the 2.25-GW program.
“[I]t continues to grow daily and exceed expectations,” Norcia said.
He said DTE’s five-year plan for cleaner generation includes spending $1 billion on its voluntary renewable program and $1 billion for solar generation development.
The utility retired two coal plants last year. DTE called it a “milestone” in its efforts to achieve net zero emissions by 2050. In the interim, it is targeting an 85% reduction in emissions by 2035 and 90% by 2040.
OLYMPIA, Wash. — Critics of a Washington bill to impose a road usage fee on electric and hybrid vehicles lined up to testify at the state capitol Thursday.
The bill (HB 1832) by Rep. Jake Fey (D) proposes to establish a voluntary road usage charge (RUC) program in 2025 that would levy a 2.5-cent fee for every mile that an electric or hybrid vehicle drives on public roads and highways. The fee would likely be calculated by an instrument connected to an EV’s odometer. The charge would then become mandatory in 2030, replacing special fees that Washington EV and hybrid drivers currently pay to the state. (See EV Road Usage Charge Bill Floated in the Wash. House.)
The measure is intended to replace shrinking state gasoline tax revenue used to maintain the state’s highways.
The bill’s critics include several business groups and contractor associations, which on Thursday testified before the House Transportation Committee, which Fey chairs. They voiced concern that HB 1832’s language could allow some road usage revenue to be redirected to non-highway transportation projects, something they contend would violate the 18th amendment of the Washington constitution, which requires gas tax and vehicle license fees deposited into the state’s motor vehicle fund be used for “highway purposes.”
“We don’t want to dilute the current [highway] funding we already have,” Mike Ennis, government affairs director at the Association of Washington Business, testified. Jerry Vanderwood, chief lobbyist for the Associated General Contractors of Washington, said highway projects already have to fight for money in the state’s budget.
Last year, Gov. Jay Inslee issued a mandate prohibiting the sale of new gas-powered cars in 2035, prompting Fey to address a road usage fee at this time.
The legislature needs to discuss and hammer out a road usage fee system to counteract shrinking gas revenues, Fey said.
Currently, electric and hybrid vehicle owners in Washington pay two annual fees that total $150. Under the current bill, starting in 2025, a vehicle owner would have the choice of paying either the $150 in annual fees or a fee calculated by odometer readings, which would be capped at $150. The RUC becomes mandatory for all EVs and hybrids in 2030.
“It’s clear that there is no other concept to replace the gas tax,” said Sharon Nelson, a member of the RUC steering committee that advised the State Transportation Commission on the issue.
Thursday’s hearing was a continuation of a hearing that was suspended Tuesday due to a lack of time.
After the hearing, Fey said changes are likely in the bill, but he expects to shepherd it to a full House vote this session.
Pacific Gas and Electric (NYSE:PCG) has reduced the total miles of power lines it intends to bury over the next three years, saying it needs to proceed more gradually to show that undergrounding can be performed cost effectively and to appease critics.
PG&E wants to eventually underground 10,000 miles of distribution lines in high fire-threat areas at a cost of $25 billion or more. The controversial plan, which needs regulators’ approval, is part of PG&E’s efforts to prevent its equipment from starting catastrophic wildfires like those in the past five years. (See PG&E Pleads Not Guilty to Manslaughter Charges.)
The utility had sought to bury 3,600 miles of lines by 2026 but revised that figure down to 2,275 miles, a move it discussed in a fourth-quarter earnings call Thursday.
“We reduced our mileage as a result of conversations with our key stakeholders,” CEO Patti Poppe said on the call. “We have to earn the right to do that underground. We have to prove that we can, in fact, do it at the unit cost that we’ve described …
“I remind myself that the Golden Gate Bridge wasn’t built in a year,” Poppe said. “It was built over time, and it’s beloved, and that’s what our undergrounding program is going to be. It’s going to be built over time, and it’s going to be beloved. And we have to earn the right to grow those miles year after year after year. And so, we’re very focused on doing that well.”
Poppe said PG&E had buried 180 miles of lines last year for less than the $3.75 million per mile that it had estimated in its earnings call a year ago. During that call, Poppe said the utility expected to bring down the cost of undergrounding to $2.5 million per mile by 2026 through efficiencies of scale and technical advances. (See PG&E Plans to Spend $25B to Bury Lines.)
The utility asked the California Public Utilities Commission to approve nearly $10 billion for undergrounding in its 2023 general rate case but revised that figure down to about $6 billion with the decreased mileage.
PG&E plans to file a 10-year undergrounding plan with the state later this year under the terms of Senate Bill 884. Signed by Gov. Gavin Newsom in September, the bill provides for expedited review of undergrounding plans submitted by large electrical corporations to the CPUC and the state Office of Energy Infrastructure Safety.
“That will clarify mileage and unit cost targets,” Poppe said. “And I also want to remind everyone that, look, this undergrounding program is very important from a risk reduction and a customer satisfaction [perspective], but it’s not a big bet. The undergrounding program is less than 20% of our total capital plan. It is flexible and dynamic in nature. We’re going to be working with our regulators and those stakeholders to make sure that we do undergrounding at a pace that they support.”
Undergrounding Opposition
The pace supported by some intervenors in PG&E’s rate case is far more limited than even the utility’s revised proposal.
In January filings, the CPUC’s Public Advocates Office, the California Farm Bureau Federation and communications companies such as AT&T questioned the feasibility and cost of PG&E’s downsized plan.
The Utility Reform Network, a consumer watchdog group, said in a Jan. 23 brief to the CPUC that PG&E had lowered its mileage target in a December filing because it knew it was falling behind meeting the 2023 goals that it had outlined a year ago.
“PG&E suggests that its mileage reduction responds to intervenor concerns about the company’s ability to achieve its February 2022 targets but never admits that PG&E itself has come to realize that those targets were unrealistic,” TURN said.
It cited an internal slide presentation it received from PG&E that said, “Work readiness for 2023 [underground] work execution is behind target as of mid-October” because of challenges with permitting, land rights acquisition and the availability of materials.
Despite the delays, the utility is “moving ahead with plans to underground 350 miles in 2023, at a forecast cost of approximately $1 billion,” TURN said. “PG&E appears committed to this path, even though it has not received any authorization from the commission for any rate recovery for its 2023 undergrounding proposal. Needless to say, PG&E’s undergrounding request is hugely controversial and subject to CPUC disapproval, in full or in part.”
TURN recommended to the CPUC that PG&E should focus its system hardening work on “installing 450 miles of covered conductor in 2023 at a cost of $358 million, with a more focused and feasible undergrounding deployment in 2023 that targets the 50 highest-risk miles at a cost of $167 million.”
“In TURN’s view, the prudent course for PG&E in 2023 would be to focus on covered conductor — a proven strategy that the commission has already endorsed — with a much more targeted use of undergrounding,” it said.
“The execution challenges that PG&E is already experiencing and the company’s lack of transparency about those problems should raise concerns,” TURN said. “The nature of the challenges underscores the huge question marks about the timing and executability of PG&E’s plan.”
BOSTON — The Massachusetts Executive Office of Energy and Environmental Affairs (EEA) has recruited two veteran New England policy makers to fill newly created positions aimed at improving regional and federal energy collaboration.
EEA Secretary Rebecca Tepper last week said the office hired Jason Marshall to be deputy secretary and special counsel for federal and regional energy affairs and Mary Louise “Weezie” Nuara to be assistant secretary.
The positions are a first within the agency to be specifically tasked with promoting regional cooperation on energy issues.
The two will serve as Massachusetts’ “emissary to promote clean energy development and procurement, build regional transmission, support grid reliability and affordability, enhance energy markets and pursue federal support,” the office said in a statement.
Marshall is a long-time employee of the New England States Committee on Electricity (NESCOE), which represents the six New England states at NEPOOL and in front of grid operator ISO-NE and other bodies. He most recently served as deputy executive director and general counsel.
Nuara is Dominion Energy’s state policy director for New England and previously worked at ISO-NE as a senior external affairs representative.
“The Healey-Driscoll Administration is going to be nimble and cooperative to achieve our clean energy goals, and Jason and Weezie will be key to these efforts,” Tepper said in a statement.
Among the new officials’ priorities will be representing Massachusetts in complicated discussions over regional transmission planning.
“We’re committed to looking at transmission on a regional level, particularly for offshore wind,” Tepper said at a renewable energy conference in Boston Thursday.
The New England states have submitted concept papers to the U.S. Department of Energy as the first step in asking for federal funding for transmission projects that would bring more electricity from Canada and offshore wind into the region.
It’s a time of huge opportunity with all the federal funding floating around.
“There are so many grants that we can’t even ask for them all,” Tepper said Thursday.
The new hires were applauded from several corners of the energy sector in New England.
“The New England states are powered by one grid, and it’s complicated. Jason is equipped to cover the full court on day one, from a deep understanding of our markets and transmission system, to expertise on federal rules and process, to working relationships with officials across New England,” NESCOE Executive Director Heather Hunt said in a statement. “Weezie brings front row experience from the vantage point of our regional grid operator and a power generator. Both Jason and Weezie are widely known to lead with respect and collaboration.”
The National Rural Electric Cooperative Association joined investor-owned utilities in urging Congress to streamline permitting of new transmission, backing a bill that would limit National Environmental Policy Act (NEPA) reviews to two years.
The House Committee on Natural Resources is holding a hearing Feb. 28 on the “Building United States Infrastructure through Limited Delays and Efficient Reviews Act” (BUILDER Act) of 2023, which has been introduced by Rep. Garret Graves (R-La.)
NRECA CEO Jim Matheson told reporters Thursday that his group, which represents almost 900 cooperatives serving 42 million people, sees an urgent need for infrastructure to connect renewables and serve new demand, such as electric vehicles.
“We’re concerned that increasing stresses on an aging set of infrastructure is going to create problematic circumstances in terms of reliability,” Matheson said. “So that’s why we’re really interested in this permitting conversation.”
On Feb. 22, the Edison Electric Institute also urged Congress to act on permitting, although the group did not endorse any legislative proposals. (See EEI Welcomes ‘Clean Slate’ on Permitting.)
Changes to permitting law have been debated for years, with earlier versions of Graves’ bill and other legislation having been floated in previous Congresses. Matheson noted that this time around a wide array of energy industry interests have lined up behind the need to change permitting laws.
“I do think that this is an interesting point in time where I hope there’s an opportunity to have a meaningful, substantive discussion and see action take place that really does move the needle on the permitting process,” Matheson said. “I think that would be in all of our interest in terms of making sure we have a reliable grid as we electrify this economy in significant ways.”
Matheson said firm time limits that allow regulators to do their jobs without leaving projects stuck in limbo are needed. NRECA said the BUILDER Act would permit a project sponsor to assist agencies in conducting environmental reviews to help speed up the process and resolve issues.
Two NRECA members described how their efforts to upgrade their grids and connect new sources of power have been slowed down by the existing permitting process.
Wisconsin’s Dairyland Power Cooperative has been replacing coal power with renewables and other cleaner sources, going from 95% coal in 2005 to 50% today with renewables set to make up 40% of its supplies by 2035, said CEO Brent Ridge. The coop is one of the developers of the proposed Cardinal-Hickory Creek transmission line from Dubuque, Iowa, to Madison, Wisconsin, to bring renewables from the resource-rich state to the biggest cities in Wisconsin.
The NEPA review process went through on time, but the project has been tied up in “unneeded litigation,” Ridge said.
The BUILDER Act would “really help provide certainty for infrastructure projects that have successfully completed the NEPA process as this project has,” he said.
North Dakota’s McKenzie Electric Cooperative deals mainly with two federal agencies that use NEPA to review infrastructure: the Bureau of Indian Affairs and the U.S. Forest Service. McKenzie CEO Matt Hanson said the co-op has 44 pending applications with BIA that need to be processed so it can serve new customers on a reservation — the oldest of which goes back to 2017.
“What do those delays in processing permits cause?” Hanson said. “Well, the first off is it prevents economic development on the reservation. Second, it impacts the environment. So, the delays in getting the permits processed means that our end consumers, most of the time, are running off generators until line power comes and connects them.”
Delays also add to the costs of projects, which are passed onto consumers under the co-op’s business model, he added.
While the BUILDER Act is set for a hearing before February ends, the new Congress just took power in early January and has gotten off to a fairly slow start, said Matheson. But other committee leaders in both the House and Senate and in both parties have discussed the permitting issue.
“There’s a lot of conversation,” Matheson said. “I do think it’s across the political spectrum as well, and we hope that we build some momentum going forward. But I don’t want to oversell you on this. I don’t have a specific prediction by congressional leaders about ‘we’re going to work on this bill by this timeframe.’”
Entergy has asked FERC to exclude some of its power plants from rules contained in MISO’s new availability-based accreditation method, warning that without exemptions, it risks a potential capacity shortfall in Mississippi.
The utility filed a waiver request last week on behalf of its Mississippi and Arkansas subsidiaries, which claim that if a 24-hour startup exclusion is applied to certain generators under the RTO’s new accreditation method, it could set off capacity deficits in the state across multiple seasons (ER23-1140).
Entergy (NYSE: ETR) said its Mississippi and Arkansas arms “are facing dramatic decreases in the capacity accreditation of the resources due to the application of MISO’s new accreditation methodology.”
It requested three-year exemptions from historical startup times being used in accreditation for the 738-MW gas-fired Gerald Andrus Power Plant in Mississippi; its partial ownership interests in Units 1 and 2 of the 1,678-MW coal-fired Independence Steam Electric Station in Arkansas; and its majority interest in Units 1 and 2 of the 1,800 MW coal-fired White Bluff Steam Electric Generating Station in Arkansas.
FERC last year gave MISO permission to conduct four seasonal capacity auctions and apply a seasonal accreditation based primarily on a thermal generating unit’s performance during tight system conditions. The expected and historical tight conditions are dubbed “resource adequacy hours” and represent periods when resource availability is less than 25% of operating margin.
The grid operator’s 2023-24 capacity auctions in April will be the first to get seasonal treatment and use the availability-based accreditation. Its previous method deducted forced outages from installed capacity values.
With the commission’s approval, MISO will treat offline resources that historically take longer than 24 hours to start up as unavailable during resource adequacy hours. In those cases, the RTO will reduce accreditation accordingly.
The 24-hour cutoff has Entergy concerned. It said if the rule is applied as written to its three plants, it will have a “material effect” on capacity values through mid-2026. The utility said the accreditation rule could cut capacity values by 25% at Gerald Andrus and by 27% at White Bluff’s Unit 2.
Entergy said it has conducted field verification at the plants and adjusted startup times to less than 24 hours. It said if it secures the waivers, accreditation values for the plants will be a “more reasonable estimate of the [resources’] expected availability.” It also said startup times at Gerald Andrus, Independence and White Bluff “were already only slightly above 24 hours” and that it fine-tuned the startup times in good faith to protect customers from expensive capacity prices.
The utility asked FERC for expedited treatment by March 7 before the seasonal auctions take place “to limit the potential for irreparable harm.”
MISO has taken no position on Entergy’s filing.
Entergy made the filing a day after FERC rejected its request to annul the new accreditation. It had argued that an accreditation hinging on generator availability during a small set of hours will produce volatile and difficult-to-predict results year-over-year. (See FERC Affirms MISO’s Seasonal Auctions, Accreditation.)
Though FERC upheld MISO’s accreditation design, Commissioner Allison Clements logged dissent, criticizing the 24-hour threshold as too generous to be effective. She said the grid operator’s decision to credit resources that take up to a full day to start up will see MISO extending credits to resources that can’t respond in time and are unlikely to be helpful during reliability issues.
