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October 7, 2024

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Hearing Shows Solar Conflict in Sun-soaked Eastern Wash.

A proposed massive solar farm is stirring controversy in southeastern Washington, pitting farmers and unions against local officials and the region’s Republican Party, while another similar project looms on the horizon.

Both projects are in the northwest corner of Benton County, just a few miles from four similar solar projects in neighboring Yakima County. All six are proposed for the same chunk of desert-like steppe habitat in the Yakima River Valley that crosses the line between the two counties. 

Benton County is home to the highly contaminated Hanford Nuclear Reservation, which is surrounded by pristine buffer zones, including Rattlesnake Ridge along the site’s western borders. The two Benton County solar farms are to be located west and southwest of the ridge on private farming and grazing areas.

On Monday, Washington’s Energy Facility Site Evaluation Council (EFSEC) held a public hearing in Pasco on a proposal by Innergex Renewable Energy to build the 470-MW Wautoma Solar Project just east of the Benton County line.

In Washington, an energy project developer has the choice of getting project approval from the state through EFSEC or from the host county. Innergex opted to go through EFSEC. 

Monday’s hearing turned out support from farmers in the immediate area and construction unions, and opposition from Benton County’s government and Republican Party.   

Québec-based Innergex is seeking to build the Wautoma project on 3,000 acres of sagebrush, of which less than 1% is being farmed. The project, which would include batteries capable of storing power for four hours, would be sited next to a major transmission line and is 30 to 40 miles from the nearest towns and cities. 

Laura O’Neill, Innergex senior environmental coordinator, said farm owners in the area are interested in the project and that the proposed site avoids environmentally sensitive lands. Western Hanford and the area west of the reservation are home to hundreds of elk, and the project’s fence would include openings for large animals to pass through.

Construction is scheduled to begin in the first quarter of 2024 and be completed by the third quarter of 2025. O’Neill said the project’s timetable and size could easily change during the design phase. 

‘Visual Pollution’

During Monday’s hearing, three members of the Robert family, which owns the 3,000 acres of primarily grazing land, lobbied EFSEC to support the Innergex proposal. Maya Robert said agricultural economics has been adversely affecting their ranching. “Solar power will help us make productive use of unproductive land,” she said.

Her uncle Robin Robert said roughly 800 sheep can share the land with the solar farm, with the animals using the panels for shade, making the project the Washington’s third proposal to develop agrivoltaics, the simultaneous use of solar panels with grazing or farming.

Stan Isley, representing the Yakima Valley Audubon Society, gave conditional support to the proposal, saying the developers must be careful of potential harmful effects to the wildlife and environment in that region.  Brendan Mercer, a neighboring grower of wine grapes, wanted to make sure the proposal’s effects on well water are studied and voiced concern about the impact of intense sunlight reflecting off panels on light-sensitive grapes.

“This proposal creates jobs and helps farmers. This is a very remote area,” said Stan Gasper, a Benton County resident. Four union leaders and members supported the project because its construction would employ hundreds, although only three to five permanent staff members would be needed after construction.

A woman representing the Benton County Republican Party opposed the project. “If you see a bunch of windmills and a bunch of solar panels, that’s visual pollution,” she said. There is an unrelated major wind and solar project several miles to the southeast within sight of the heavily populated Tri-Cities, which has sparked opposition because many residents don’t want to look at the wind turbines on their landscape.

Benton County resident George Penn opposed the Innergex project for visual reasons, arguing solar panels should be set up solely on the Hanford site, which is partially off-limits to the public. Area resident Lorre Gettre said farmers don’t always know the consequences of putting solar farms on their lands and voiced fears about the storage batteries leaking.

The Innergex site is on land zoned for agriculture. Last December, the Benton County Board of Commissioners — which vehemently opposes the wind and solar project south of the Tri-Cities — passed a law prohibiting large solar projects on agricultural lands. But Innergex argued Monday that the project is still consistent with Benton County’s comprehensive growth management plan.

Other Projects Loom

Meanwhile, a second solar farm is now in play for western Benton County.

Florida-based renewable energy company BrightNight confirmed to NetZero Insider Monday that it plans to build a 500-MW solar farm just south of Rattlesnake Ridge.  

The Hop Hill Solar project would be built on 17 square miles of cattle- and sheep-grazing land with the panels to cover about 30% of the site. The rest will be kept as grazing land, including the shady areas beneath the panels located eight to 10 feet above the ground, said Meribeth Sawchuk, BrightNight vice president of communications. While BrightNight has several projects on the drawing board across the nation, it has not yet completed any, she said.

No timetable has been set for the project. Unlike Innergex, BrightNight, plans to get approvals for its project from both the Benton County government and EFSEC. This will be the first renewable energy project in Washington to seek approval from both county and state governments. Swachuk said residents tend to be cautious about allowing solar farms on lands in their home counties. “It made more sense for us to coordinate with the county,” she said. 

All this is taking place as the Board of Yakima County Commissioners is considering whether to declare a moratorium on approving new solar farms as they examine the long-term impacts of this blossoming industry in the region.

Three of the four solar projects proposed for Yakima County are taking the EFSEC approval route, including two 80-MW solar farms by North Carolina-based Cypress Creek Renewables — High Top and Ostria — near the county’s eastern border.  

EFSEC is also considering whether it will approve at the 80-MW Goose Prairie solar farm by Seattle-based OneEnergy, while Yakima County is considering approval of the nearby 94-MW Black Rock project by California-based BayWa r.e. (See ‘Strength of Sunshine’ Brings Solar Projects to Wash. County.)

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DC Circuit Sends FERC Back to Drawing Board on MISO ROE

The long-running saga of the battle over MISO transmission owners’ return on equity continued Tuesday when the D.C. Circuit Court of Appeals vacated FERC’s 2020 order setting the rate at 10.02% (16-1325).

FERC must yet again determine what the just and reasonable ROE is in a case that has gone on for nearly a decade, with seven different commission chairs and three different presidential administrations (EL14-12, et al.).

In its ruling, the D.C. Circuit helpfully included a two-page-long chart (p.13-14) to show the three ROE figures FERC had set since November 2013, when MISO transmission customers complained that the then 12.38% rate was too high: 10.32% in 2016, 9.88% in 2019 and 10.02% in 2020. The fluctuating figures owed to the commission repeatedly changing the inputs for the complex formula that determines the ROE.

To get the latest figure, FERC used three different financial models — discounted cash flow (DCF), capital asset pricing (CAPM) and risk premium (RPM) — to determine a zone of reasonableness and set the ROE at its midpoint. (See FERC Ups MISO TO ROE, Reverses Stance on Models.) That reversed the commission’s previous stance against using the RPM just six months before, when it set the 9.88% ROE using only DCF and CAPM.

The court determined that was an arbitrary and capricious decision. It noted that in November 2019’s Opinion 569, FERC “spent several pages demonstrating the impressive extent of” the RPM’s deficiencies. But later in May 2020’s Opinion 569-A, “FERC changed its tune.”

“FERC is, of course, entitled to change its mind,” the D.C. Circuit said. “But to do so, it must provide a ‘reasoned explanation’ for its decision to disregard ‘facts and circumstances that’ justified its prior choice. Here, FERC failed to do that.”

In setting ROEs for private companies, like the MISO TOs, FERC essentially estimates what their stock price would be if they were publicly traded. Using the RPM, it estimates the cost of equity using the premium that investors would expect to earn on a stock investment over the return they would expect to earn on a bond investment.

In 2019, FERC argued, among many other things, that there was no evidence that investors used the RPM to make decisions and that the model takes into consideration previous ROEs, which may have been rendered unjust and unreasonable.

But in 2020, “FERC failed to adequately explain why it no longer mattered that investors don’t use this model,” the court said. “Instead, it simply noted that investors expect a premium on a stock investment over a bond investment, and that investors track the returns FERC allows. Both statements are true, but neither offers a persuasive reason to think that the risk premium model as FERC applied it here offers meaningful insight into investor behavior.”

FERC also failed to address the model’s circularity, the court said, merely stating that “all of the models contain some circularity.”

“That explanation doesn’t meaningfully engage with the ‘particularly direct and acute’ circularity problems presented by using old rates to set new ones,” the court said.

The D.C. Circuit did, however, dismiss the majority of the petitioners’ complaints about the 2020 order, including aspects of the DCF and CAPM and that the commission should have used the median of the zone of reasonableness, rather than the midpoint. The court found that these arguments conflicted with prior legal decisions on FERC’s ratemaking, but that the commission’s unjustified reversal on the RPM “is alone enough to make FERC’s rate orders arbitrary and capricious.”

FERC Chair Richard Glick, who had lambasted the then-Republican majority over the reversal, celebrated the court’s decision. “Reversing FERC on the risk premium model is a big win for consumers, helping make energy costs more affordable,” he tweeted.

With its order vacated, “FERC still lacks a judicially validated mechanism to set electric utility ROEs,” ClearView Energy Partners noted. “With the need to invest billions of dollars to upgrade the nation’s transmission system looming, FERC’s response will be closely watched by all stakeholders.”

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Akins Steps down as AEP President; Sloat to Become CEO

American Electric Power (NASDAQ:AEP) announced Wednesday that Nicholas Akins, CEO for the last 11 years, has resigned from his role as president of the company and been replaced by its current CFO, Julie Sloat.

In a brief press release, the Columbus-based utility said its board of directors would also promote Sloat as CEO beginning Jan. 1.

Sloat was named CFO in January 2021 after serving as a senior vice president of treasury and risk for two years and for nearly three years prior to that as president and COO of AEP Ohio.

AEP noted that Akins’ remaining time as CEO was part of the corporation’s “executive succession plan.” After Sloat takes over, he will become executive chair of the board, according to the release, and “will remain an executive and officer of the company.”

Akins has been president and CEO of AEP since 2011 and chairman of the board as well since 2014.

Nick Atkins (AEP) FI.jpgOutgoing AEP CEO Nicholas Akins | AEP

“Nick has transformed AEP during the 11 years that he has led the company. His focus on innovation, technology and modernization of the grid and AEP’s generation fleet is enabling clean, reliable and resilient energy to fuel growth in the communities that AEP serves,” Sara Martinez Tucker, lead director of the board, said in the release. “He also has built an open, collaborative culture that embraces diversity, equity and inclusion. AEP is fortunate that Nick has focused on developing a group of strong and capable leaders to ensure the company’s continued success.”

Akins praised Sloat as “an exceptional leader who has successfully led key strategic areas for the company. Her financial expertise and positive relationship with investors have been essential for the execution of our long-term strategy, enabling us to deliver strong earnings quarter after quarter while continuing to raise guidance and provide consistent dividend growth.”

“During her time as CFO, she has improved the financial performance of the company, and she also enhanced the performance and culture of AEP Ohio during the transition to competitive markets,” Tucker said. “The board is confident that she is the right person to lead AEP during this dynamic time for the industry and the company.”

Sloat initially joined AEP in 1999 as a credit risk analyst but left for 15 months in July 2008 to become vice president of investor relations job with Tween Brands, a clothing company. She returned to the utility in September 2009 as vice president of regulatory case management.

She has a bachelor’s degree in business administration with a double major in finance and economics and an MBA from Ohio State University. She completed the Nuclear Reactor Technology Program at the Massachusetts Institute of Technology.

“This is a time of tremendous change and opportunity for AEP as we invest in new energy technologies and infrastructure to provide clean and reliable energy to our 5.5 million customers,” Sloat said. “I’m honored to have the opportunity to lead an amazing team of nearly 17,000 employees.”

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NY Scorecard Makes Way for Utility-scale Agrivoltaics

New York’s upcoming annual solicitation for large-scale renewable energy may include a new siting scorecard that would encourage solar developers to build agrivoltaic strategies into their projects.

“Proposals with co-utilization commitments will receive favorable scoring credit, and these commitments will be included in the awarded agreements,” said Jeremy Wyble, senior project manager at the New York State Energy Research and Development Authority (NYSERDA).

The authority wants its expanded Smart Solar Siting Scorecard to “drive change” so that developers site “smarter” projects, Wyble said Tuesday during an American Solar Grazing Association webinar.

Comments on the proposed update to NYSERDA’s 2021 scorecard were due at the end of July, and Wyble said the goal now is to review those comments and include the updated version with the next Tier 1 solicitation for large-scale renewables. Tier 1 projects are designed to help New York’s load-serving entities meet the state’s Renewable Energy Standard requirements and can include solar, wind, geothermal, battery, hydro and geothermal technologies.

While NYSERDA included a simplified scorecard for submissions to last year’s Tier 1 solicitation, the authority used it mainly for informational purposes. This year, however, NYSERDA plans to require developers to submit the expanded 2022 version with their bids. It will “hold more weight” than it did last year, returning an actual score based on 160 total points, according to Jessica Bacher, executive director of the Land Use Law Center at Pace University. Bacher supported the authority’s efforts to update the scorecard.

Of the 160 points, 95 are allocated to agricultural protection, 35 to environmental protection of forested lands, 25 to community benefits and collaboration, and 5 for innovation. Developers would earn points for minimizing land impacts, which then would trigger certain strategies that are either mandatory or optional based on that land-use score.

Optional strategies would carry extra points that developers can earn by including them in their proposals to offset land-use impacts. There would be no points awarded for mandatory strategies.

The bulk of co-utilization strategies on the scorecard are optional because agrivoltaics is a new field, and it’s not “appropriate” yet to mandate them within the new scorecard incentivization structure, Bacher said.

The two mandatory co-utilization strategies on the scorecard are conducting a site survey or engaging landowners or farmers to assess feasibility and land suitability for production of preferred crops or vegetation species; and engaging the farming community to determine feasibility and solicit interest in grazing activities in or around the project.

High-scoring optional strategies include:

      • designing for the land’s current and future farming uses;
      • maintaining pollinator habitat, crop production or grazing in long-term project operations; and
      • incorporating regenerative farming practices, such as plant cover crops or low tillage, for maximum carbon sequestration.

Engagement with the community is a recurring theme in the scorecard, Bacher said.

NYSERDA plans to require developers to complete the scorecard for the upcoming solicitation if they are proposing to build a solar project with a capacity of 20 MW or larger on 100 acres or more.

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New England’s Reliability During Heat Wave Came with Emissions Spike

A huge bump in emissions, fueled by generating facilities burning through 6 million gallons of oil, was the price that New England had to pay for making it through last month’s heat wave without any significant grid reliability problems.

New data released by ISO-NE on Wednesday gave the latest illustration of the uncomfortable tradeoffs that the region faces when the weather causes high demand for electricity.

The six straight days of above-average heat was the longest such stretch in New England over recent years. Those days were responsible for much of a spike in oil consumption by power generators, which ISO-NE noted took place July 12-25.

Generators used about 6 million gallons of oil, with oil-fired generation accounting for up to 11% of the electricity produced in New England during some hours of the hottest days in that stretch.

Firing up those oil plants brought with it a huge jump in emissions: During the week of the heat wave, New England power plants emitted 845,967 metric tons of CO2, roughly 50% more than the same period last year and 17% more than a record-setting heat wave in 2021.

heat_wave_emissions (ISO-NE) Content.jpgGenerators burn more oil and, therefore, produce more emissions, when demand is high on New England’s grid. | ISO-NE

 

But the addition of oil generation did its job to steady the grid, and even with some unplanned outages, ISO-NE only had to issue an MLCC/2 alert, which lets resources know to hold off on testing or maintenance that might dent their availability.

“Our Operations staff managed the grid through teamwork, precise forecasting and rigorous planning, helping to ensure New Englanders had the electricity they rely on for their comfort, health and safety,” ISO-NE COO Vamsi Chadalavada said in a statement.

ISO-NE said that behind-the-meter solar production played a role in ramping down demand during the brightest daylight hours of the heat wave.

“On July 19, BTM PV generation reduced system demand by roughly 4,000 MW,” the grid operator said. “Without contributions from BTM PV, system demand would have approached levels forecast for weather much hotter and more humid than average.”

Where solar slowed down was where oil came in, during the late afternoon and evening hours.

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NRDC: Early Worries About ISO-NE’s Capacity Accreditation Approach

The Natural Resources Defense Council is urging ISO-NE to ensure that thermal resources get the same scrutiny as renewables, as the grid operator develops a new approach to capacity accreditation.

The environmental group has commissioned GE Energy Consulting to put together a full analysis of the options facing stakeholders and ISO-NE, but in the interim, it offered some early thoughts to the NEPOOL Markets Committee this week.

In a presentation, NRDC’s Bruce Ho and consultant Nick Pappas said that ISO-NE’s preferred method of measuring marginal reliability impact (MRI) risks under-valuing some components of clean energy resources’ contributions to reliability.

“Declining marginal value does not imply existing resources [are] no longer needed for reliability, [but] solely that additional resources of similar class provide less marginal benefit,” NRDC said in its presentation.

Ho and Pappas gave the example of a battery resource, developed in 2028 with an initial MRI of 90%. Under the average accreditation approach, which measures reliability contributions based on their share of their class’s (in this case, batteries) total reliability contribution, the MRI declines to 41% over a 15-year period.

Using marginal accreditation, which sets a resource’s accredited capacity based on the MRI of an incremental change in size, the MRI drops to 13%.

“Marginal accreditation omits about one-third of the resource’s total lifetime reliability contributions from a capacity awards standpoint,” NRDC said. “How does this omission impact policymaker and market participant incentives for clean energy investment?”

Later on, the presentation answered its own question: “If clean energy resources’ reliability values are undercompensated, ISO-NE [is] likely to see the development of sub-optimal resource mix.”

NRDC is planning to put forward the results of the GE analysis at the MC’s September meeting.

Other MC Business

In the second day of its two-day meeting, the committee also discussed:

  • proposed changes to the Generation Information System to sort and transfer screen enhancements, and an effort to accommodate hourly tracking;
  • modifications to the schedule for Forward Capacity Auction 18;
  • proposed revisions to enable do-not-exceed dispatch requirements for solar assets;
  • proposed revisions to clarify the calculation inputs to the capacity transfer right values for pool-planned units in the Forward Capacity Market settlement; and
  • proposed revisions to address the limited participation of storage-as-transmission-only assets in markets, including real-time energy market obligations, and metering requirements associated with storage operated as a transmission asset.
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DOE Launches $675M Program to Build Critical Mineral Supply Chain

The U.S. Department of Energy is consolidating its portfolio of critical mineral research and development programs in a bid to build a domestic supply chain of materials needed to decarbonize the national economy.

The new, wide-ranging Critical Materials Research, Development, Demonstration and Commercialization Application (RDD&CA) program will be funded with $675 million from the Infrastructure Investment and Jobs Act (IIJA).

In a request for information released Tuesday, the DOE said the program with the tongue-twisting abbreviation would “integrate, expand and accelerate DOE’s strategy to build resilient, diverse, sustainable and secure domestic supply chains that support the clean energy transition and decarbonize energy, industrial, manufacturing and transportation sectors while promoting safe, sustainable, economic and environmentally just solutions to meet current and future needs.”

According to the RFI, the RDD&CA program was authorized in the Energy Act of 2020, the bipartisan package passed in December of that year. The funding in the IIJA includes $600 million to be used over four years to promote critical materials recycling, innovation, efficiency and alternatives. Another $75 million will provide two years of funding for the development of a Critical Material Supply Chain Research Facility, also authorized by the Energy Act.

The projects using this combined funding will “make our nation more secure by increasing our ability to source, process and manufacture critical materials right here at home,” Energy Secretary Jennifer Granholm said in a press release announcing the RFI. “The [IIJA] is supporting DOE’s effort to invest in the building blocks of clean energy technologies, which will revitalize America’s manufacturing leadership.”

U.S. dependence on China and other foreign sources for the critical minerals needed for a range of clean technologies — for example, the lithium-ion batteries used in electric vehicles — has long been an easy target for Republican critics of President Biden’s clean energy goals. According to DOE, global demand for critical materials in general could grow by 400 to 600% over the next several decades, while demand for lithium and graphite, also used in EV batteries, could increase by as much as 4,000%.

China controls up to 80% of lithium refining capacity and 60% of battery component manufacturing, according to figures from BloombergNEF.

The need for building out a domestic supply chain for these critical materials has also provided an opportunity for bipartisan agreement — such as the funding for the RDD&CA in the IIJA.

An additional $140 million in the law is being used to support the development of “a new facility to demonstrate the commercial feasibility of a full-scale rare earth element and critical minerals extraction and separation refinery using unconventional resources,” such as coal waste and ash and acid mine drainage. An RFI for that project was released in February.

Critical mineral supply chains could also get a boost from advanced manufacturing credits in the Inflation Reduction Act, passed by the Senate on Sunday and now awaiting a vote in the House of Representatives. Battery cells and modules are eligible for credits of $10 to $35 per kWh of capacity, and a range of critical minerals will be able to take a 10% tax credit on their production costs.

In 5 Years

The DOE defines critical materials “based on [their] importance to a range of energy technologies and the potential for supply risk,” the RFI says.

The Critical Material RDD&CA will take a “material-by-material approach,” prioritizing the following minerals:

      • neodymium, praseodymium and dysprosium, used for magnets in wind turbines and electric and fuel cell vehicle motors;
      • lithium, cobalt, nickel, graphite and manganese, used for lithium-based batteries needed for energy storage;
      • platinum group metals used for catalytic converters in fuel cells and in electrolyzers for green hydrogen production;
      • gallium, used for light emitting diodes and wide bandgap power electronics in high voltage power generation;
      • germanium, used for microchips needed for sensors, data and control in smart manufacturing.

The new initiative will also be based on DOE’s core “pillars” for supply chain buildout, which include diversifying and expanding domestic critical mineral supplies, developing substitutes and promoting efficiency across the supply chain, as well as a circular economy approach to repair, reuse, recycling and remanufacturing.

The RFI lays out tentative program priorities for each of the critical mineral groups. For example, DOE envisions a range of research and development activities, pilots and demonstration projects for all aspects of the supply chain for neodymium, praseodymium and dysprosium, from mining and processing to recycling. A tighter focus is used for lithium, cobalt and other key battery minerals, with R&D and pilots planned only for mining, extraction and coproduction, in which multiple materials are produced together and bring in similar revenue streams.

DOE is looking for input and ideas on how best to organize and execute the program, with comments due by Sept. 9. The RFI includes a range of questions, from what criteria should be used to measure program success, to concerns about “the ideal timing and desirable features, terms and conditions of off-take agreements that would stimulate the private sector investment necessary” to achieve program goals.

Questions also focus on community benefits and engagement, including job creation, labor standards and workforce training, especially in disadvantaged and low-income communities.

How long it will take to develop a domestic supply chain for critical minerals is also a core concern. “What are the most high-impact opportunities to diversify supply, develop substitutes, increase material and manufacturing efficiency and drive reuse and recycle of critical materials for energy technologies … in the next 5 years?” the DOE asks. “What quantitative impact could the Critical Materials RDD&CA program have on domestic supply chains in 5 years?”

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PJM Sees Additional $603M ‘Data Center Alley’ Transmission Spend

VALLEY FORGE, Pa. — Dominion Energy (NYSE:D) plans $603 million in additional transmission spending to serve the unprecedented growth of data centers near Dulles Airport in Virginia, and FirstEnergy (NYSE:FE) is also reporting an explosion of data center demand, PJM officials said Tuesday.

“We’ve seen a lot of data center growth in this particular area, Loudon County,” Ken Seiler, PJM vice president of planning, told the Transmission Expansion Advisory Committee. “Seventy percent of the world’s Internet traffic flows through there. Over the last few months [data center demand has] ramped up tremendously. … We’re trying to a get a handle on what the projected growth rate and if it’s sustainable.

“We’ve never seen anything like this, being so concentrated,” he added. “And we don’t see any evidence it’s going to be stopping anytime soon.”

PJM designated Dominion to construct a $603 million “immediate need” project to address short-term reliability issues through 2025.

Data Center Alley (PJM) Content.jpgPJM and Dominion are attempting to serve unprecedented growth of data centers near Dulles Airport in Virginia by building new transmission between new Wishing Star and Mars substations. Existing data centers are identified in green; those in design/construction (red); in planning (dark blue) and inquiry stage (yellow). | PJM

Seiler said PJM is looking for “broader, regional-scale projects” to solve reliability problems beyond 2025, to serve anticipated load growth of more than 10,000 MW over next five years in the Dominion transmission zone and FirstEnergy zone in Northern Virginia and Frederick County, Md.

PJM announced the Dominion immediate need project last month, but provided the first cost data and details at Tuesday’s TEAC meeting. (See PJM Orders Dominion ‘Immediate Need’ Projects to Serve Load Jump in ‘Data Center Alley’.)

The project will include a new Wishing Star substation ($180 million); a new Mars substation ($167 million); 500-kV and 230-kV line extensions ($132 million); Brambleton substation upgrades ($12 million), Loudoun breaker replacements ($5 million); 230-kV Line #2079/Davis Drive upgrades ($15 million) and risk/contingency/escalation costs ($92 million).

The required service date is June 1, 2025.

Dominion is already constructing 11 “supplemental” transmission upgrades estimated at $197 million and two “baseline” transmission upgrades totaling more than $32 million to address load growth in the area, dubbed “Data Center Alley.”

Earlier in the TEAC, Dominion described solutions for 13 supplemental projects totaling $366 million, all but two of them the result of data centers or other “customer service” drivers.

Seiler said PJM and Dominion will be coordinating outages and using demand response and behind-the-meter generation to protect existing loads during construction. “Any and all things are on the table at this point,” Seiler said.

In addition, the PJM planning team will be “assembling late this month to consider what additional options do we have to determine what the long-term regional solution will be,” he added.

Data centers have grown from 30 MW each to 60 MW and “even as high as 90 MW,” said Seiler. Data center campuses have grown from 200 MW to as much as 600 MW each, he said. Seiler said data centers are only providing Dominion two year’s notice or less of when they want to begin operations.

Dominion’s load is growing by 3% per year for 2022-2027, all of it from data centers, while PJM’s load growth has been 0.4% or less annually. (See “Data Center Alley,” Dominion CEO: SCC Order for OSW Performance Guarantee ‘Untenable’.)

Cost Allocation

“It’s a little too soon to tell yet,” Seiler said when asked about cost allocation of the upgrades. “Right now, I don’t have those numbers available.”

But he noted that PJM rules require regional allocations for double-circuit 345-kV lines and above.

“The way our rules are set up today, anything double-circuit 345-kV and above — and you’re talking 500 [kV] here in some cases — will be allocated 50% on a load-ratio share,” he explained in an interview after the meeting. “… Then, the lower voltage stuff is all contained within the Dominion zone, or [based on] the distribution factors and where that power flows — so, whoever benefits from it. So, we have to run [analyses on] all that.”

The supplemental projects described Tuesday will be allocated to Dominion’s zone but also included in the base cases PJM uses to evaluate potential regional solutions Seiler said.

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Dominion CEO: SCC Order for OSW Performance Guarantee ‘Untenable’

Three days after the Virginia State Corporation Commission approved Dominion Energy’s (NYSE:D) 2.6-GW Coastal Virginia Offshore Wind (CVOW) project, the utility’s CEO, Robert Blue, said the 42% capacity performance guarantee in the decision is “extremely disappointing” and “untenable.”

The guarantee “would require DEV [Dominion Energy Virginia] to financially guarantee the weather, among other factors beyond its control, for the life of the project,” Blue said during Dominion’s second-quarter earnings call on Monday.

“Given a project of this magnitude, however, the commission’s performance guarantee creates an unprecedented layer of financial one-way risk to DEV and is inconsistent with the utility risk profile expected by our investors,” he said. “We plan to actively engage with stakeholders on the unintended consequences of that provision and are reviewing all public policy options including reconsideration or an appeal.”

The performance guarantee was part of the SCC decision approving a $78.7 million rate hike for the project while warning that the state legislature left ratepayers facing “unprecedented risks” of cost overruns and delays on the $21.5 billion project. (See related story, Virginia Regulators OK $79M Rate Hike for Dominion OSW Project.)

The performance guarantee was one of several measures the SCC put in place with the goal of controlling costs and protecting ratepayers. However, the commission acknowledged that the guarantee would not protect customers from cost overruns or abandonment costs.

Dominion is, in fact, projecting a lifetime capacity of 42% for CVOW over 30 years. But, Blue said, “there are obviously factors that can affect the output of any generation facility notwithstanding a reasonable and prudent action [of] the operator, including natural disasters, acts of war or terrorism, changes in law or policy, regional transmission constraints, or a host of other uncontrollable circumstances.”

He also noted that the SCC did not impose a performance guarantee when approving Dominion’s previous solar energy projects in 2021, saying they were not required for projects developed to comply with the 2020 Virginia Clean Economy Act. “The same outcome should be made here,” he said.

While the performance guarantee was clearly top of mind for Blue, the call also covered the potential impact for Dominion of the Inflation Reduction Act and its 15% minimum corporate tax, the utility’s upcoming plan to invest $1.5 billion in new solar, and the explosion of data centers and power demand in Northern Virginia.

Data Center Alley

Dominion has connected 70 data centers in its Virginia service territory since 2019, with more than 2,600 MW of capacity, Blue said. Now dubbed Data Center Alley, eastern Loudon County is the center of that growth, with more than 25 million square feet of data centers now online and another 4 million square feet in development, according to the county’s Department of Economic Development.

Data centers now represent 20% of Dominion’s electricity sales, and on top of that growth, Blue says the peak demand of individual data centers in the region is also growing. Further, once a new data center is online, he said, it is ramping up to full demand more quickly than previously.

“A single data center typically has demand of 30 MW,” he said. “However, we’re now receiving individual requests for demand of 60 MW or greater.”

PJM has predicted a 2,600-MW jump in peak demand from Dominion’s system by 2027 — a 12% increase from its load predictions a year ago and the same capacity as the CVOW project, which is scheduled to be completed in late 2026, Blue said.

In response, Dominion is planning to accelerate its plans for two new 500-kV transmission lines in the area, but the utility is facing potential transmission constraints in the future and has put a “pause on new data center connections while we work on solutions to alleviate the constraints as quickly as possible,” Blue said.

The utility is “reviewing the current capacity constraint analysis, including performing additional in-depth analysis substation by substation; engaging further with customers and other stakeholders … to pace new connections’ ramp-up schedules, and reviewing a variety of technical alternatives to address areas of concentrated load,” Blue said.

Dominion recently submitted plans for the first 500-kV line to PJM and expects to file for approval from the SCC “in the coming weeks,” Blue said. The utility also expects “to resume new connections in the near term, but how much and how quickly is still be determined,” he said.

But Buddy Rizer, executive director of economic development for Loudon County, said officials there are “still trying to figure out what it means. We don’t know how many of the 4 million square feet [in development] will have power.”

“Dominion surprised everyone” with the pause, which was announced late in July, he said. The pause is also causing uncertainty for additional projects in the early stages of development, he said.

Blue provided no information on how many projects might be affected by the pause in interconnections, but he said any slowdown is not expected to hurt electricity sales or revenue. The pause is also not affecting any data centers outside Loudon County, he said.

“We expect to overcome any headwinds by the acceleration of needed new-build transmission projects from later in the long-term plan to earlier,” which will increase capital investment and recovery in the utility’s five-year capital growth plan, he said.

Inflation Reduction Act

Responding to analyst questions about the IRA, Blue called the bill, passed by the Senate on Sunday, “still a moving target” as the House of Representatives prepares to consider the bill later this week, with a possible vote coming as soon as Friday. (See related story, Senate Passes Inflation Reduction Act.)

While additional amendments could still pop up, Blue rated the bill on a “really high level” as “pretty good — really positive from a decarbonization incentive perspective; really positive from a utility, customer perspective.” For example, Dominion and its customers stand to benefit from the IRA’s extension of the wind production tax credit and its nuclear and clean energy tax credits, he said.

Blue also predicted that the IRA’s 15% corporate minimum tax rate could have a negligible impact for the utility, which is already a “cash taxpayer” but is “shielded by our inventory of tax credits,” which have kept the company’s tax rate around 5.25%.

Applying the company’s tax credits to the 15% minimum tax rate could cut that figure even further to 3.75%, he said.

Nuclear and Solar

The SCC has also approved Dominion’s application to recover costs of close to $4 billion for extending the licenses of its North Anna and Surry nuclear plants. The two units at North Anna generate about 1.9 GW, and Surry’s two units 1.6 GW. Together, they provide about 30% of Virginia’s power, according to Dominion.

The utility is also preparing its next clean energy filing in the coming weeks, which will include about a dozen solar and energy storage projects. “The filing will represent at least $1.5 billion of utility-owned and [recovery] eligible investment, further de-risking our growth capital plan,” Blue said.

Earnings

The company announced a GAAP net loss of $453 million ($0.58/share) for the second quarter, compared with net income of $285 million ($0.33/share) for the same period in 2021.

Non-GAAP operating earnings for the second quarter were $658 million ($0.77/share), compared to $628 million ($0.76/share) for the same period in 2021.

According to CFO James Chapman, the difference between GAAP and operating earnings reflect the impact of economic hedging activities, gains and losses on nuclear decommissioning trust funds, charges associated with the sale of Kewaunee nuclear power station in Wisconsin, regulated asset retirements and other adjustments.

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Counterflow: 45Q: Money for Nothing

tesla powerwallSteve Huntoon | Steve Huntoon

Binge watching the earlier Star Trek series (highly recommended), there is this enigmatic, fantastically powerful entity, Q. Now it seems that the Manchin-Schumer package is going to create an enigmatic, fantastically powerful Q for the Internal Revenue Code.

Up until now this section 45Q has been a limited source of tax credits for carbon capture projects. BTW, 87% of the tax credit claims didn’t comply with IRS requirements.[1] As for direct grant subsidies for carbon capture, GAO recently reported that DOE spent $684 million in taxpayer money for six carbon capture coal projects of which zero are operating.[2]

Under Manchin-Schumer the 45Q spigot will be opened wide with taxpayers on the hook for carbon capture at power plants and elsewhere at a cost of $85/ton, and for direct carbon capture at a cost of $180/ton.[3]

Why would taxpayers want to:

  • pay twice the cost for one type of carbon capture versus another?[4]
  • pay a multiple of the tax credit cost of emission reductions from wind and solar generation of about $32/ton?[5]
  • pay many multiples the cost of carbon offset credits that range from $7-$22/ton?[6]
  • pay an even bigger multiple of the cost of emission reductions from LED lighting of $5/ton?[7]

Money — both public and private — is inherently limited for any and all purposes. Not spending efficiently inherently undermines the task at hand.[8]

The 45Q Cost Is Likely to Be Ginormous, Contrary to Congressional Claims

The Joint Committee on Taxation and the Congressional Research Service claim that new 45Q is going to cost U.S. taxpayers an average of $323 million per year over the next 10 years.[9]

That seems fanciful.

45Q supporters say they want to stop the massive shift from coal to natural gas and renewables,[10] the shift that is responsible for enormous reductions in carbon emissions.[11]

These supporters presumably know what they need, and they lobbied for the $85/ton level. And won. The Carbon Capture Coalition says: “The bill includes all of the Carbon Capture Coalition’s top legislative priorities for the 117th Congress.”[12]

This Coalition goes on to say that the bill could deliver 210-250 million tons of annual emission reductions.[13] So at $85/ton that would be about $20 billion per year.

Princeton’s ZERO Lab projects this level of annual emission reductions is reached in 2031, increasing rapidly to 450 million tons by 2035,[14] when the annual cost would be about $40 billion per year.

So let’s call it about $30 billion per year, and contrast that with the Joint Committee on Taxation/CRS claim of $323 million per year. Congress is understating taxpayers’ cost of new 45Q by a factor of about 100. A mere bagatelle.

One More Thing

There’s another problem with the credit to the extent it succeeds in heading off coal retirements that would otherwise occur. That’s because coal plants with carbon capture still emit about as much carbon as new gas plants without carbon capture.[15] So in those instances taxpayers would be paying an enormous subsidy for nothing.

Of course new (and existing) gas plants could install carbon capture. But the incentive is relatively small because (ironically) there’s so much less carbon to capture. New gas plants also will have to confront the prospect of low energy prices when so much other generation — wind, solar and now coal — will have low if not negative marginal costs.

My head hurts.

P.S. This discussion of 45Q isn’t intended to imply that the bill overall isn’t better than nothing, especially since the alternative might be nothing for a long time. But taxpayers deserve better when it comes to provisions like this one.

 

[2] https://www.gao.gov/assets/gao-22-105111.pdf, Table 1 on page 7. This table shows the Petra Nova project as operating, but as reported by GAO it was suspended in May 2020 and has not resumed operations. So DOE funding is 0 for 6. The GAO report reveals shocking mismanagement of taxpayer dollars by DOE.

[4] The Carbon Capture Coalition advocated these levels based on the relative costs of the two carbon capture technologies, https://carboncapturecoalition.org/wp-content/uploads/2021/09/Proposed-AJP-and-Infrastructure-Investments-1.pdf. This doesn’t make sense: Why pay twice as much to subsidize one technology just because it costs twice as much?

[5] https://www.catf.us/wp-content/uploads/2017/12/CATF_FactSheet_Cost_of_CO2_Avoided.pdf, adjusting the $48.76/ton value, based on a PTC of $23/MWh, for the current/future PTC of $15/MWh.

[7] The average light bulb in the U.S. is on 1.6 hours per day averaging 47.7 watts, which is 27.86 kwh/year. https://www1.eere.energy.gov/buildings/publications/pdfs/ssl/2012_residential-lighting-study.pdf. LED bulbs use 84% less electricity, cost about $2.50 each, and last 25,000 hours or more, for a lifetime of 42.8 years at 1.6 hours/day. Incandescent bulbs over a collective lifetime of 42.8 years would use a total of 1,192 kwh, which reduced by 84% is a savings of 1,001 kwh, which is 1 MWh. Reduced electric use reduces carbon emissions at 0.47 tons/MWh, https://www.catf.us/wp-content/uploads/2017/12/CATF_FactSheet_Cost_of_CO2_Avoided.pdf, so reducing emissions by 1 MWh at a cost of $2.50/bulb costs $5.30/ton.

[8] One example I’ve discussed before is offshore v. onshore wind where the former takes 11 times the subsidy for a given MWh of generation, which means we can get on average 11 times more onshore wind from a given dollar of subsidy. https://energy-counsel.com/docs/Offshore-Wind-Edifice-Complex.pdf. Ditto rooftop v. grid solar.

[9] Joint Committee on Taxation, https://www.finance.senate.gov/imo/media/doc/7.29.22%20Estimate%20of%20Manchin%20Schumer%20agreement.pdf, Title I, Subtitle D, Part 1, line 4, the total for years 2022-2031 divided by 10; adopted by the Congressional Research Service, https://crsreports.congress.gov/product/pdf/R/R47202, Table 5.

[10] https://www.eenews.net/articles/big-payout-more-co2-greens-split-over-dems-ccs-plan/, quoting the head of the Wyoming Mining Association: “From the industry standpoint, we see it as necessary to keep coal viable going forward.”

[11] Gas plants displacing coal plants are responsible for 90% of the carbon emission reductions in PJM. https://www.energy-counsel.com/docs/NRDC-Prescribes-More-Carbon-Emissions.pdf. Also, https://www.energy-counsel.com/docs/we-see-through-a-glass-darkly.pdf.

[13] Id.

[15] A study of Wyoming coal plants says that coal plant emissions after carbon capture would be 0.29 kg/kwh, https://pubs.acs.org/doi/pdf/10.1021/acs.est.1c08837, page 9876, which converts to 650 lbs/MWh. EPA data on new gas plants shows average carbon emissions of 777 lbs/MWh, https://www.epa.gov/system/files/documents/2022-01/egrid2020_data.xlsx, PLNT2016 tab, column PLCO2RTA, for sample plants Riviera Beach, Colorado Bend II and Cape Canaveral.