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November 17, 2024

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Virginia Regulators OK $79M Rate Hike for Dominion OSW Project

Virginia regulators warily approved a $78.7 million rate hike for Dominion Energy’s 2.6-GW Coastal Virginia Offshore Wind (CVOW) project Friday, warning that the legislature had left ratepayers facing “unprecedented risks” of cost overruns and delays on the massive $21.5 billion project.

With a projected capital cost of $9.8 billion, the project “will likely be the largest capital investment, and single largest project” in the utility’s history, the State Corporation Commission (SCC) said in its 45-page order, which also approved the interconnection and transmission facilities to connect the project to the PJM grid (PUR-2021-00142). “The project will also likely be the costliest project being undertaken by any regulated utility in the United States, with the exception of Southern Co.’s ongoing Vogtle nuclear project, and will likely be the most expensive on a dollars-per-kilowatt of firm capacity basis.”

Total project costs, including financing costs minus investment tax credits, are estimated at $21.5 billion, including a $7.22 billion return on equity based on Dominion’s 9.35% ROE rate.

The new rate adjustment clause (Rider OSW) will cost a residential customer using 1,000 kWh/month an average monthly bill increase of $4.72 over the projected 35-year lifetime of the project, with a peak increase of $14.22 in 2027, the commission said.

Ratepayers at Risk

“While neither staff nor any respondent opposed approval of CVOW, significant concerns were raised throughout this proceeding regarding affordability and the financial risk to ratepayers,” the commission noted. “The project is truly distinctive in numerous respects, encompassing cost, size, technology, complexity, ownership and risk. … No other utility or independent developer has attempted to construct and operate an offshore wind project of this size in the United States.”

Unlike other East Coast states backing offshore wind, Virginia did not choose procurement models to mitigate the risk to ratepayers.

Instead, Dominion will construct, own and operate the project, with its costs presumed prudent under the 2020 Virginia Clean Economy Act (VCEA) as long as the total levelized cost of energy — including tax credits and the costs of transmission and distribution facilities — does not exceed 1.4 times the cost per megawatt-hour of a simple cycle combustion turbine.

“Every other state that is pursuing large-scale offshore wind is utilizing power purchase agreements or offshore renewable energy certificate contracts, which limits the risks to customers by shifting construction, operational and market risks from customers to the project’s owner,” the SCC noted.

Cost-control Protections

Acknowledging concerns raised by the Office of the Attorney General’s Division of Consumer Counsel, the state Department of Energy, Walmart, Clean Virginia and Appalachian Voices, the commission ordered Dominion to:

  • file a notice with the SCC within 30 calendar days if it determines that total project costs are expected to exceed the current estimate, or if the final turbine installation is expected to be delayed beyond Feb. 4, 2027. The company currently projects an in-service date by the end of 2026;
  • include any material changes to the project in each annual Rider OSW update application it files before the project’s commercial operation, and a written explanation for any cost overruns; and
  • hold ratepayers harmless for the cost of replacement power if CVOW’s energy production fails to meet its projected 42% annual net capacity factor, as measured on a three-year rolling average.

Dominion contended “it would be inappropriate for the company to be put at risk if it fails to meet the capacity factor upon which it has justified and supported this project,” the SCC said. “We disagree. This particular risk for this particular project should not fall on the company’s customers.”

Dominion did not immediately respond to a request for comment on the SCC’s concerns. In a press release, Dominion CEO Robert Blue said the company was happy with the commission’s approval and is “reviewing the specifics of the order, particularly the performance requirement.”

The commission acknowledged that its 42% performance standard will not protect customers from cost overruns or abandonment costs, the latter of which “would not be inconsequential,” the commission warned. “Even if the project is abandoned at the end of 2023, Dominion still estimates it would have prudently incurred approximately $3.7 billion of costs to be recovered from customers.”

The commission warned rising commodity prices and supply chain problems could result in construction delays and cost overruns.

“As a first-mover project, there is no developed supply chain, including equipment suppliers, specialized installation vessels, and infrastructure to handle the transportation and installation of the equipment,” the SCC said. It noted that turbine supplier Siemens Gamesa has suffered supply chain disruptions and that the company has two installations ahead of CVOW that will be receiving the same turbines.

No EPC Contractor

The commission also said the designs for the turbines, monopiles, transition structures and other components have not been finalized and questioned whether Dominion’s 3% contingency estimate ($300 million) was sufficient “for a project of this size and risk.”

“Dominion has also opted not to use an engineering, procurement and construction (EPC) contractor on the project, which the record shows is a departure from how it has managed construction of prior generation facilities. In prior cases, the use of an EPC contractor enabled the company to shift materials, labor and schedule risk away from the company and its customers, as well as risk of construction delays and cost overruns,” the commission said. “In this case, however, Dominion is instead managing the project in-house using multiple interrelated contractors.”

The VCEA declared “in the public interest” the construction or purchase by a public utility up to 5,200 MW of offshore wind. Dominion’s choice of “a construction and ownership model that places most of the risks on customers … is one of the reasons why Clean Virginia seeks an independent assessment of whether the utility-owned model for this project should not be used for the next 2,600 MW tranche of offshore wind,” the SCC said.

Windmill Shoreline Infographic (Dominion Energy) Content.jpgDominion Energy

Effective Sept. 1, Rider OSW will recover financing costs on $661.7 million in capital expenditures during the rate year, as well as allowance for funds used during construction accrued on Dominion’s books.

Like all VCEA-related costs, Rider OSW will be a non-bypassable charge generally paid by all Dominion retail customers — even those who purchase power from competitive service providers — with limited exceptions. “Prior to the VCEA, shopping customers would generally not be responsible for the costs of Dominion generation facilities to the extent they procure for their own energy and capacity from someone other than Dominion. The VCEA now directs that shopping customers pay for VCEA-related costs, with limited exceptions.”

Transmission

The project — 176 14.7-MW wind turbines that Dominion says will produce enough carbon-free power for up to 660,000 homes — will be located 27 miles off the coast of Virginia Beach.

The capital cost includes a projected $1.15 billion for the onshore Virginia facilities, including $774.3 million for transmission-related work and approximately $374.2 million for substation-related work (2021 dollars).

The SCC order approved Dominion’s route for the offshore export circuits and the route for the 4.4-mile underground route for its onshore export circuits from the cable landing to a new Harpers Switching Station. Also approved was an overhead route from Harpers to the existing Fentress Substation.

Transmission upgrades are estimated to be about $215 million. The final costs of transmission network upgrades are unknown because ongoing study work in the PJM generation queue was placed on hold to clear the current backlog.

“The transmission interconnection facilities are a significant component of this project, and [Dominion] has experienced delays and cost overruns on recent transmission projects,” the SCC said.

Jagdmann Suggests Legislative Action

Judy Jagdmann (NARUC) Content.jpgSCC Commissioner Judith Jagdmann | NARUC

In a concurrence, SCC Commissioner Judith Jagdmann observed that CVOW “is a legislatively favored project. If the elements of [the VCEA] are met, the costs of the project are presumed ‘reasonable and prudent’ — which means, in effect, ‘ratepayers pay,’” Jagdmann wrote.

But she said the General Assembly could reduce the impact on ratepayers by making general fund appropriations or authorizing the use of auction proceeds from the Regional Greenhouse Gas Initiative. “Such action may be appropriate given the public policy support for and economic development aspects of this project,” she wrote.

She said the legislature’s requirement for yearly cost recovery proceedings provide “in theory, the opportunity in upcoming sessions to determine if additional steps are warranted to reduce the economic burden that will be placed on Dominion’s customers as the project proceeds.”

“Timing may be of the essence,” she added. “In less than 18 months from now, Dominion plans to have spent close to $4 billion of capital costs on the project.”

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Transwest Express Seeks to Join CAISO

The developers of a transmission line intended to carry Wyoming wind power to California have asked to join CAISO, a move that could extend the ISO’s reach more than 700 miles across the West and help the state meet its 100% clean energy mandate by 2045.

But the ISO’s plan to adopt a new participating transmission owner (PTO) model for the line and others like it has raised concerns.

The planned TransWest Express line “intends to place under the CAISO’s operational control all of [its] project transmission lines and associated facilities … that will connect to the existing bulk power system in Wyoming and Utah as well as directly to the [CAISO]-controlled grid in Nevada,” the company said in its application to become a PTO.

TransWest would consist of 732 miles of transmission lines in three linked segments: a 405-mile, 3,000-MW HVDC system between Wyoming and Utah; a 278-mile, 1,500-MW HVAC line between Utah and Nevada; and a 49-mile, 1,500-MW HVAC transmission line in Nevada. It will connect in Utah to lines serving the Los Angeles Department of Water and Power (LADWP) and in Nevada to CAISO’s grid and balancing authority area.

The project is an “advanced stage of development, focused on pre-construction matters including tower design and testing; interconnections; contracting with engineering, procurement and construction contractors; and financing,” the application says. “All major permits have been acquired, and 100% of the easements/authorizations to build on private lands have been secured.” Major parts of the project could be in service by 2026, it says.

Subscriber Model

TransWest would be CAISO’s first subscriber participating transmission owner (SPTO), a new model that would give the ISO operational control of the lines without increasing its transmission access charge (TAC), currently more than $16/MWh.

Last year, TransWest conducted a FERC-approved open-solicitation process that offered firm, long-term transmission service to California via Utah and Nevada. It decided to allocate 100% of its capacity to Power Company of Wyoming, owner of a 3,000-MW wind farm in the south-central part of the state. FERC approved the arrangement in February.

Both TransWest and Power Company are wholly owned affiliates of The Anschutz Corp., a privately held company based in Denver controlled by billionaire Phillip Anschutz, a conservative who made much of his fortune from oil and natural gas. Anschutz has sought to profit from California’s clean-energy mandate under Senate Bill 100.

To meet the 2045 goal, the state will need to import as much as 10 GW of out-of-state wind by 2040, at least half of it from Wyoming, according to projections by the California Public Utilities Commission and the California Energy Commission.

CAISO’s recent 20-year transmission outlook examined new transmission needed for the undertaking, predicting overall costs of $30 billion that includes $12 billion to carry wind from the Great Plains and Rocky Mountain states. (See CAISO Sees $30B Need for Tx Development.)

Stakeholder Meeting

In an Aug. 1 presentation and stakeholder question-and-answer session, Deb Le Vine, CAISO director of infrastructure contracts and management, described the TransWest project and how the new SPTO model would work.

“In trying to implement a new type of participating TO, there are a number of things to consider,” Le Vine said. “The intent was to go ahead and come up with a model that allows a remote transmission facility to become part of the ISO grid but to have subscribers that would pay for the transmission.”

Most of the transmission capacity for TransWest is subscribed in at least one direction and would not rely on ISO for funding, Le Vine said in her presentation.

Subscriber rights to the line will be treated as encumbrances, similar to existing contracts on transmission lines joining CAISO, she said. An SPTO could recover incremental charges from CAISO market participants using the lines, for instance, if non-subscribers send capacity from south to north on TransWest, she said.

“We’re looking to go ahead and support this concept by an amendment to [CAISO’s] Transmission Control Agreement” (TCA) without tariff changes, she said.

Need More Info?

Some stakeholders felt CAISO needed to provide more information that spells out the details of how the new subscriber model would work and to engage in a stakeholder process, making tariff changes.

Chris Devon, director of market intelligence in the West for advisory firm Customized Energy Solutions and a former CAISO senior policy developer, asked De Vine if the subscriber model would be detailed in a paper or only through slide decks like the one that she used in her presentation.

De Vine said it would be presented through slide decks because the new model does not require changes to CAISO’s tariff, only to its TCA.

Devon said he thought the changes should be vetted in a stakeholder process and made through tariff changes, not through the TCA. He expressed concern with CAISO using an abbreviated process to adopt a complex, untested TO model that diverges from current market practices.

The subscriber model resembles processes being discussed in the ISO’s transmission service and market scheduling priorities stakeholder initiative, Devon said. That initiative is meant to develop a “long-term, holistic framework for establishing scheduling priorities,” the ISO says.

The new model could impact the CAISO market and stakeholders, Devon said. “It just seems to me like this is actually creating a new type of policy as opposed to just being something that should be done through this change to the TCA, so I think it should be stakeholder-ed.”

The subscriber model’s potential costs to ratepayers remains unclear.

Asked to comment, the CPUC, which has been trying to control rising ratepayer bills for the state’s increasingly expensive electric system, said in an email that it is “actively participating on behalf of ratepayers in the CAISO’s stakeholder processes related to the newly proposed subscriber participating transmission owner model concept related to TransWest Express.”

“As such, we are unable to provide a specific comment on the TransWest Express transmission line at this time as we continue to develop our analysis.”

Comments on the Aug. 1 presentation are due Aug. 15. Stakeholders have until Sept. 19 to comment on the TransWest application.

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Opening of Wash. Green Hydrogen Plant Delayed to Mid-2023

Washington’s first industrial-scale green hydrogen production facility has fallen an additional six months behind its original start date.

The facility near East Wenatchee on the Columbia River in Central Washington was originally set to go online in late 2021. (See Wash. PUD Breaks Ground on Hydrogen Plant.) Supply chain and COVID matters delayed startup to the end of this year or early 2023. Now the plant is expected to commence operation in the summer of 2023, Douglas County Public Utility District spokeswoman Meaghan Vibbert told NetZero Insider in an email.

“We had the usual COVID supply chain issues, bids coming in more than anticipated, and more recently, we have changed course in building design. We had purchased a metal building, but the energy code and safety requirements influenced us to change to a concrete structure, which is slated to go out to bid late this month,” Vibbert wrote.

The project has been working with a roughly $25 million budget, up from an earlier $20 million estimate. Its goal is to produce two tons of hydrogen a day.

The Wells Dam, about 50 miles upstream of East Wenatchee, is the primary power-generating resource for Douglas County PUD. Excess power and water from the dam will eventually be sent to the new hydrogen plant to produce green hydrogen fuel via electrolyzers, which separate the oxygen and hydrogen molecules in water.

While the Douglas PUD has been in talks with several potential customers, no contracts have been signed yet, Vibbert wrote. 

Besides providing hydrogen for vehicle fueling stations still in the birthing stage, the plant’s potential future contracts will likely include the steel and ammonia industries. The PUD recently bought an extra 90 acres next to the plant’s 40-acre site to prepare for future expansion if needed.

Washington is seeking to become host to one of four to eight national hydrogen hubs to be funded by $8 billion in U.S. Department of Energy grants. Gov. Jay Inslee and the state’s Department of Commerce have been working this year to coordinate the state’s activities around winning the DOE funding. State lawmakers in March overwhelmingly passed a bill to create a new office to support the development of green hydrogen and other alternative fuels. (See Wash. Looks to Boost Prospects for Winning Hydrogen Hub.)

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DC Circuit Backs Kentucky Munis on Transmission Rate ‘Pancaking’

FERC failed to consider the impact of potential rate increases when it allowed Louisville Gas and Electric (LG&E) and Kentucky Utilities (KU) to partially exit market power mitigation measures, the D.C. Circuit Court of Appeals ruled Friday (19-1236).

The court vacated parts of a March 2019 order and rehearing orders in September 2019 and September 2020 (ER19-2396, ER19-2397). (See FERC Again Rejects LG&E-KU Mitigation Exit.)

The commission imposed rate de-pancaking provisions to resolve horizontal market power concerns after LG&E and KU merged in 1998 and left MISO in 2006. The utility was acquired by PPL (NYSE:PPL) in 2010.

As a condition for allowing the utility to leave MISO, FERC required it to agree not to charge its wholesale power customers duplicative “pancaked” transmission rates for power shipped to or from MISO, so long as the RTO did the same.

In March 2019, the commission agreed the de-pancaking provisions — spelled out in the utility’s Schedule 402 — could be removed because loads located in its market would have access to enough competitive suppliers.

But the commission sought to protect customers that had made business decisions based on the de-pancaking provisions by requiring LG&E and KU not to end de-pancaking during a transition period. It set the transition at 10 years for the cities of Paducah and Princeton, Ky. (P&P), which had invested in the Prairie State coal-fired generator connected to the MISO grid.

The D.C. Circuit said that while “the commission reasonably found that sufficient competition would survive the return of pancaking, it was arbitrary and capricious for the agency to ignore the effect pancaking would have on rates.” It also said FERC failed to adequately explain two aspects of its transition requirements.

While there were no more than seven competitive wholesale energy suppliers for the grid when FERC approved the LG&E-KU merger, by 2018, more than 100 suppliers could competitively sell to the grid, the commission said.

LG&E and KU’s “neighbors include some of the largest independent grids on the continent — MISO and PJM Interconnection LLC — giving those customers ready access to independent power suppliers,” the court said.

But the court said FERC erred in “backhanding the effect that pancaking would have on rates.” It quoted an expert for municipal utilities protected by Schedule 402 who estimated that the end of de-pancaking would raise municipalities’ rates by at least 15%, with one customer’s rates rising 47%.

“Importantly, this rate analysis goes beyond just looking at competition because, as the commission has recognized, markets do not always function perfectly,” the court said. “Yet here, the commission expressly refused to even consider the effect ending de-pancaking would have on electricity rates. The commission held, instead, that because de-pancaking was imposed to protect competition, that was the only factor it needed to consider in ending the program.

“By refusing to consider the material effects of its order on customer rates — a factor that its own regulations identify as a key component of the public interest, the commission engaged in ‘unreasoned, arbitrary and capricious decision-making,’” the court concluded.

The court said that although vacating the commission’s action may cause some disruption, “that disruption seems unlikely to be severe, as our decision implicates in large part the same type of rates that are required to be de-pancaked in the short term under the transition mechanism. We therefore vacate the commission’s decision to permit [LG&E and KU] to end de-pancaking under Schedule 402 and remand for the agency to reconsider its decision in light of the direct and indirect effects ending de-pancaking would have on customers’ rates.”

Win for LG&E/KU

LG&E and KU claimed one victory in the appeal, convincing the court that FERC acted arbitrarily in extending the de-pancaking of P&P’s rates related to their investment in a hydroelectric project until their power agreements expire in 2057.

“That reasoning cannot be reconciled with the commission’s determination that the transition mechanism was meant to extend de-pancaking only for a ‘limited period of time.’ The commission had just said that 10 years of mitigation was enough to protect P&P’s similar long-term investment in Prairie State. Yet here, the commission concluded that mitigation must continue for an additional 38 years — simply because the hydropower agreements contained a concrete end date of 2057.

“That makes no sense. If 10 years of protection suffices for an ownership interest that continues ‘indefinitely,’ something in the neighborhood of 10 years would seem the relevant time frame to protect another exceptionally long investment,” the court said. “The commission failed to explain why the fact that an agreement will terminate by a date certain justified extending the mitigation term for nearly four decades.

“Should the commission conclude on remand that the public interest supports ending de-pancaking under Schedule 402, it must either better explain this aspect of the transition mechanism or take a fresh approach to the question,” the court said.

‘Inexplicable’ Rejection

The court also said FERC’s reasoning for declining to protect the entirety of the Kentucky Municipal Power Agency’s  eight-year transmission reservation with MISO was “inexplicable.”

“The commission’s holding that transmission reservations are not ‘separate financial commitment[s]’ meriting independent protection was conclusory and inconsistent with the plain criteria of the transition mechanism,” the court said. “The commission’s competition finding does nothing to justify reaching a different result for transmission reservations than it did for power purchase agreements. The commission’s claim that de-pancaking Energy Agency’s entire transmission reservation would unduly extend its remedy to future power agreements was also baseless. …

“If the commission chooses again to end Schedule 402 de-pancaking on remand, it must come forward with a logical explanation for its decision here that is consistent with the purpose and scope of the transition mechanism, or it must extend de-pancaking on reasoned terms to Energy Agency’s transmission contract,” the court said.

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SPP MOPC Approves Change Addressing Fuel Limitations

SPP stakeholders Friday unanimously approved an urgent revision request that expands the ability of market participants facing fuel limitations to include opportunity costs in their mitigated offers.

The Market Monitoring Unit (MMU) drafted the revision request (RR452) over concerns that a potential rail strike and other coal-delivery issues could create difficulties in meeting system demand in late summer and this winter.

The measure creates a new circumstance for fuel limitations caused by abnormal fuel supply, transportation or market limitations not rising to the level of force majeure. Documentation must be provided to the MMU for its determination of eligibility on case-by-case basis. Current rail limitations fall under the new language.

The Markets and Operations Policy Committee passed the measure 56-0, with nine abstentions, during a special conference call. The change was added to the Integrated Marketplace’s protocols before the work week ended. The Market and Regional Tariff Working Groups also approved it.

Raleigh Mohr (SPP) Content.jpgMMU supervisor Raleigh Mohr | SPP

Raleigh Mohr, an MMU supervisor, said the Monitor saw a need for a transparent market mechanism to conserve scarce fuel when conditions do not rise to force majeure. He said the change is both a market benefit and a reliability benefit.

“Coal deliveries are falling short of nominated demand from our market participants,” Mohr said. “The market benefit is that the opportunity cost of the scarce fuel is transparent in the market price. The reliability benefit is that that this change would slow down or alleviate some of the issues being seen immediately with the coal transportation constraints … by assigning an opportunity cost to it.”

Oklahoma Gas & Electric’s Usha Turner spoke for several MOPC members concerned about RR452’s unintended consequences and its lack of parameters. She said that based on her reading of the protocols, “force majeure very clearly includes labor disputes, labor material shortages [and] restrictions imposed by lawfully established civilian authorities.”

“I’m not sure why the agreement of an opportunity cost adder isn’t already within the MMU’s authority,” Turner said. “It seems to me that the language is already there. So, the question is kind of, ‘Why do we need this language?’ We’re not adding something entirely new. That isn’t a declared force majeure or biofuel supplier or a permit limit by EPA or something specific. It is unbounded.”

To ease concerns, the MMU said it would update MOPC during its October meeting on the measure’s implementation and potential bounds to limit the scope of opportunity costs.

“There are tariff elements we have to work with. We want to see if this tool is effective,” MMU Director Keith Collins said.

Email Vote Held on Temporary RAS

MOPC declined to act on a last-minute agenda addition requesting endorsement of modification to a temporary remedial action scheme (RAS). However, members did agree to conduct an email vote that will close Friday.

The Transmission Working Group approved the temporary RAS early last week, revising its operation to not last more than two years. Invenergy’s Arash Ghodsian noted that the minor modification was the only change to a previously approved RAS.

Invenergy proposed the temporary scheme so that its Thunderhead Wind Farm can operate at its full nameplate capacity (300 MW) when it becomes operational later this fall. The facility, located in northeast Nebraska, was to interconnect with Nebraska Public Power District’s R-Line, a proposed 220-mile 345-kV line put on hold in 2020 when a U.S. district court revoked a federal permit because it would disturb the endangered American burying beetle during construction.

Without the R-Line, Thunderhead is limited to 195 MW. The RAS would detect when a nearby 345-kV line is open and trigger a direct trip of circuit breakers at Thunderhead.

The Operating Reliability Working Group and the System Protection and Control Advisory Group have joined the TWG in endorsing the proposal.

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NJ Celebrates Completion of First Phase 2 Community Solar Project

NEPTUNE TOWNSHIP, N.J. — The 500-kW community solar project covering the six roofs of a storage facility in this Northern Jersey town have yet to start pumping out electrons and utility bill savings to subscribers. But that didn’t stop the state Board of Public Utilities from celebrating the project Monday as the first to be completed in the second and final phase of its community solar pilot program.

The pilot was originally planned to run three years, but the large number of projects proposed during the first two years — 150 projects totaling 240 MW — persuaded the BPU to make the program permanent beginning in 2023. A straw proposal for the permanent program could be released in October or November, with the permanent initiative rolled out in early 2023, said Taryn Boland, chief of staff to BPU President Joseph L. Fiordaliso.

The agency earlier said it expects the permanent program to award projects totaling 150 MW each year.

The Neptune project is one of 10 community solar projects developed by Solar Landscape of Asbury Park on 800,000 square feet of roofs owned by Extra Space Storage, of Salt Lake City. Together, they will generate 6.5 MW and generate clean energy for 1,400 households. While completed, the first project is not yet operational due to grid connection issues.

Speaking at an event to celebrate the completion of the first project, Jane Cohen, executive director of the Governor’s Office of Climate Action and the Green Economy, said the Extra Space Storage projects demonstrate the “critical” importance of the community solar program.

NJ Community Solar Neptune (Solar Landscape) Alt FI.jpgA 500-kW community solar project covering commercial rooftops in Neptune Township, N.J. will provide enough clean electricity to power 1,400 homes. | Solar Landscape

 

“Community solar is the opportunity for everyone to receive the benefits of clean energy, including those lower energy costs, without the upfront capital, and without having to access a rooftop or ground level space for solar panels,” she said.

Federal officials have taken note of New Jersey’s progress, last week naming it as one of five states that will provide advice and input to a community solar initiative created by the U.S. Department of Energy and the Department of Health and Human Services.

“It’s a big deal,” Cohen said.  “This [federal] pilot program will result in cheaper, cleaner energy and a one-stop shop that will remove barriers to accessing these programs.”

The federal agencies will develop an online platform to help households in the Low Income Home Energy Assistance Program (LIHEAP) and other low-income assistance programs sign up for community solar projects in their areas. Administered by HHS, LIHEAP helps low-income families with heating and cooling costs, as well as weatherization and energy-related home repairs. Other states that will advise the project are Colorado, Illinois, New Mexico and New York. (See HUD, DOE Aim to Boost Low-income Community Solar.)

Slow Installation

For all the developer interest in executing community solar projects in New Jersey, however, the pilot program has been slow to get them over the finish line. To date, just 17 of the 150 approved projects have been installed, with a combined capacity of 35.6 MW, or about 15% of the total capacity awarded, BPU records show. About 120 of the approved projects remain in the pipeline, records show.

The program faced criticism last year from developers concerned that the BPU was slow to announce the projects approved in the second phase and create the permanent program. (See Slow Progress of NJ Community Solar Pilot Draws Fire.)

The New Jersey Solar Energy Coalition, which represents 27 companies involved in solar development, said in May that the program has not advanced at the pace expected. Since then, only a few additional projects have come online, and developers have complained that it has been very difficult to get projects connected to the grid in some parts of the state. (See NJ Community Solar Slowly Advances and Solar Developers: NJ’s Aging Grid Can’t Accept New Projects.)

Solar projects across the nation have struggled with supply chain issues in the aftermath of the COVID-19 pandemic, and solar developers say getting municipal approvals has sometimes been slow in New Jersey.

BPU spokesman Peter Peretzman said there “are a number of issues that have resulted in slower than anticipated installation, including some issues common to the entire solar industry and some issues more specific to community solar.

“Our experience with the pilot program affords us an opportunity to understand and seek to address, where possible, the issues causing delays with community solar projects in the design of the permanent program,” he said.

Solar Landscape developed about half of the BPU’s installed projects and has completed all of the eight projects approved to go forward in the first phase of the community solar pilot. Shaun Keegan, the company’s CEO, said one reason for the pace of the company’s project completion is that the rooftop projects Solar Landscape pursues are easier and have fewer permitting difficulties than some other project types, such as carports and those on landfills.

Kevin Dunshee, the company’s chief commercial officer, said the company has worked hard to create a ready pool of trained staff; it recognized that there could be an elevated demand for solar panels, and so created an inventory in advance.

Meeting Low- and Moderate-Income Requirements

The company has not been hindered by the sometimes hard-to-meet BPU program rules designed to ensure that low- and moderate-income households benefit from community solar. The rules require that 51% of the subscribers be from that demographic.  

Finding those low- and moderate-income subscribers has not been easy for many community solar developers, who often partner with local non-profit and community organizations to spread the word.

“The 49%, we get pretty quickly,” Dunshee said, adding that they tend to be “people who don’t even necessarily care about the discount, they’re about green energy, they’d like the whole message of community solar.”

The low- and moderate-income portion of the subscribers is more difficult to attract, he said, “because you’re talking about people [who] can’t afford to make mistakes,” due to their economic circumstances.

“I think the most important thing for us is [to provide]) education, getting them to understand that this is a state program, it’s a Board of Public Utilities program, the discounts are guaranteed there’s no cost to get in or out,” he said.

For its Neptune project, Solar Landscape worked with Interfaith Neighbors of nearby Asbury Park, which provides affordable housing, nutrition, neighborhood revitalization and other services, and the Affordable Housing Alliance, a Neptune-based organization that works to provide housing and education.  

In a sign of the effectiveness of those partnerships, Solar Landscape announced that it is developing a project on another Extra Space Storage facility in Monmouth County that will provide power for all 130 residents of a nearby low-income property. As a result, 100% of the residents will be subscribers, the company said.

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Biden Initiative Aims to Up Federal Use of Performance Contracts

The Richard B. Russell Federal Building in Atlanta may soon be sporting advanced wind energy panels containing dozens of mini-turbines — 9 inches across — that could provide up to 2 million kWh per year of clean power for the building.

The innovative technology is just one part of a $117 million energy services contract that will cut energy use, energy bills and greenhouse gas emissions at 12 federal buildings across Georgia.

The contract between the U.S. General Services Administration (GSA) and Southern Company, one of the nation’s largest utilities, was announced Wednesday in Atlanta as part of the Biden administration’s new Climate Smart Buildings Initiative aimed at increasing federal agencies’ use of such energy service performance contracts (ESPC).

Under an ESPC, a private sector company finances and installs energy-efficient equipment on one or more federal buildings, with the goal of providing a guaranteed level of energy savings, usually for an extended term, which for federal contracts can go up to 25 years. The government pays the private company a predetermined amount for the upgrades, but only if the new equipment delivers the energy savings guaranteed in the contract.

As described in a White House fact sheet, these contracts “[pay] for today’s needed renovations with tomorrow’s bill savings without requiring upfront taxpayer funding.”

ESPCs are used in a range of institutional contexts, according to Mark Fowler, director of government affairs for Ameresco, a leading performance contracting company based in Massachusetts. In addition to federal contracts, his company also works with state and local governments and hospitals and schools.

In the case of the GSA contract with Southern Company, the utility has agreed to assure energy savings at the buildings by installing a range of energy and water efficiency upgrades including more efficient heating, cooling and lighting, digital building controls, low-flow and -flush water fixtures and the wind energy panels.

“The investments we’re making here in Georgia demonstrate how investing in sustainability is a triple win ― creating good-paying, clean-energy jobs, reducing energy costs and tackling climate change,” GSA Administrator Robin Carnahan said in an agency press release. “The federal government wants to lead by example by leveraging our scale and buying power to help drive these efforts.”

According to the fact sheet, the new initiative “is expected to catalyze $8 billion of private sector investment by 2030,” create 80,000 jobs and cut GHG emissions from federal buildings by as much as 2.8 million metric tons a year ― “the equivalent of removing 600,000 gas-powered cars from the road.”

The initiative will also leverage $250 million from the Infrastructure Investment and Jobs Act, the fact sheet said, “to promote innovative decarbonization strategies through performance contracting,” like the Windwall panels planned for the rooftop of the Russell Building in Atlanta.

Developed by Alabama-based American Wind Inc., the panels generate wind power through the “ducted,” smaller turbines, which each sit in a “shroud” or collar that funnels wind into the turbine and increases the wind velocity, said Dan Yost, the company’s chief marketing officer.

“They actually use different math than traditional wind turbines,” Yost said. “We can manipulate the velocity of the wind, so essentially, [the] panels of our wind turbines increase the ambient wind speed by around three times.”

And sitting high on an urban commercial rooftop, the panels also have a very low cut-in speed ― when they start producing power ― of 1.5 mph and can keep spinning with winds as high as 140 mph, according to company spec sheets. They can also operate in extremely low and high temperatures.

The Russell Building will have three 100-kW panels, according to the GSA, and each panel is about 10 feet by 11 feet, Yost said.

‘Get Them Done’

Federal efforts to promote performance contracting are not new. Under successive challenges from former President Barack Obama, federal agencies signed $4.2 billion in performance contracts between 2011 and 2016, with 21 federal agencies awarding contracts for 340 projects.

While many of those projects continued during the Trump administration, advocates say the number of new contracts and investments recently hit an all-time low, with only $251 million in contracts signed in 2021. Biden wants to increase those numbers to a “sustained” $1.2 billion a year by 2030, according to the fact sheet.

A commitment to performance contracting must come from the top, said Jennifer Schafer, executive director of the Federal Performance Contracting Coalition, an industry group.

“When there was never anything coming from the [Trump] White House that said, ‘Hey, these things are good; use them to achieve your goals,’ people just said, ‘It’s a lot of work; we not going to do it. The administration doesn’t care if [we] do,’” Schafer said.

“It certainly will make a difference to have the White House come out and say, ‘We have an initiative around these contracts; get them done,” she said.

Ameresco also sees the initiative as a strategically well-timed opportunity, Fowler said.

“Despite all of the new infrastructure funding investments that Congress has authorized over the last couple of years, there is still a significant gap and need within federal facilities for deferred maintenance and infrastructure backlogs that are going unaddressed,” he said. “Performance contracts offer a really great solution for these entities to address some of their big infrastructure needs and improve their efficiency, improve their resilience.”

Ameresco has done multiple federal projects, including installing over 150 kW of solar panels at the National Archives and Records Administration facility in College Park, Md., but agreed that federal requests for proposals for performance contracts have fallen off.

The allocation of IIJA funds for performance contracting, as outlined in the fact sheet, should provide another significant boost for the industry, Schafer said, allowing federal ESPC agreements to go “deeper.”

“How do you get to net zero? You can’t always do that from energy savings alone,” she said. “You may not be able to achieve all the resiliency you want from energy savings alone, so a little money might go a long way,” for example, by helping to install a microgrid.

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Cyber Ambassador Nominee Says US Leadership Needed

President Biden’s pick to head the State Department’s recently launched Bureau of Cyberspace and Digital Policy pledged Wednesday to “elevate and integrate cyber and digital policy in U.S. diplomacy” and build productive cybersecurity relationships with the nation’s allies.

Nathaniel Fick’s comments came during his confirmation hearing before the Senate Foreign Relations Committee, where he was joined by four other nominees to various diplomatic posts. The State Department created the new bureau in April; currently it is headed by Jennifer Bachus, a career foreign service official. If confirmed, Fick would also become the first Ambassador at Large for Cyberspace and Digital Policy.

Introducing Fick at Wednesday’s hearing was Sen. Angus King (I-Maine). King noted that Fick — who is also from Maine — has extensive cybersecurity experience, having served as a Marine in Iraq and Afghanistan, later as CEO for the nonprofit Center for a New American Security working on “issues of … international ramifications of cyber,” and then as CEO of cybersecurity software developer Endgame. He is currently general manager of information security for Elastic, an online search company that acquired Endgame in 2019.

“If you took a blank sheet of paper and tried to design a person to fit this new position, you would have come up with someone of Nate Fick’s extraordinary qualifications and background,” King said.

King also reminded his fellow senators that the creation of the cyber ambassador post was a recommendation of the Cyberspace Solarium Commission, of which King was the co-chair. He urged the committee not only to confirm Fick to the new post, but to approve the Cyber Diplomacy Act, which passed the House of Representatives last year and would formally establish the new bureau as a permanent addition to the State Department.

“The idea here is, we want someone who gets up every morning thinking about the international ramifications of [cybersecurity], and that’s what this office will do,” King said. “I commend the administration for taking the initiative to create this [bureau] within the State Department, but I believe we also need legislation to codify the existence of the office so it’s not something that may come and go with the whim of a particular administration.”

Fick Pledges Leadership, Positive Vision

Fick told the committee that he saw three key focus areas in his new role. First, he said the U.S. must work to strengthen adherence to the international framework surrounding cybersecurity laid out by the United Nations, which “affirms that international law applies to state conduct in cyberspace and lays out norms” that guide members’ behavior in cyberspace. He also agreed it was essential for the U.S. and its allies to ensure there are consequences for their peers who engage in egregious misconduct online, echoing a stance that King has taken in the past. (See King, Mandia Warn of ‘Unlimited’ Cyber Dangers.)

“Norms are more effective in binding together our allies than they are in dissuading our adversaries,” Fick said. “To reduce the frequency and severity of damaging cyber incidents, we must collaborate across the U.S. government and with partners around the world to deter malicious cyber activity and impose meaningful consequences on states that engage in it and those that willfully harbor cybercriminal organizations.”

Fick’s second key priority is to promote fairness in the global digital economy by preserving “the free flow of data across international borders” while also ensuring that data privacy and confidentiality are respected. Promoting fairness also means supporting open and transparent standards, as well as ensuring that new innovations are available for all to access. Third, Fick said the U.S. must partner with the private sector, civil society, and other governments to “champion a positive vision for digital freedom and digital inclusion while working to combat digital authoritarianism.”

Portman Warns Against Overlap

Rob Portman (Senate Foreign Relations Committee) FI.jpgSen. Rob Portman (R-Ohio) | Senate Foreign Relations Committee

Committee members expressed no serious reservations about either the nominee or the new bureau. However, Sen Rob. Portman (R-Ohio) voiced concerns about how Fick’s role would fit in with other recent appointments to leading cybersecurity posts in the administration. In particular, Portman said Fick’s position “overlaps with the office of the National Cyber Director,” currently held by Chris Inglis, the first cyber director who was confirmed last year. (See Inglis, Easterly Define Roles in Confirmation Hearing.)

“We seem to keep adding more and more top cybersecurity positions to our government, and the org chart troubles me,” Portman said. “More importantly, what troubles me is that without accountability, I’m worried that things will happen and it’s too easy to point fingers, as we saw in the Colonial Pipeline incident; you probably recall [that] everyone was pointing fingers.”

Fick responded that the rationale for the new office is to give the State Department a voice in the administration’s discussions about cybersecurity that it has not previously had. Especially in light of the cyberthreats posed by Russia, China and other rivals of the U.S., Fick said that “diplomacy should be our tool of first resort.” However, he also said he shared Portman’s concerns about mission overlaps and would work to avoid them.

“I think in addition to my military experience, my experience building and leading a business instilled in me an appreciation for a clear chain of command and … kind of a wry sense that it is always easy to add, but it’s hard to subtract,” Fick said. “I have full confidence that we can carve out the right swim lanes, and I hope that, if confirmed as the inaugural ambassador leading this office, we could create clear lines of responsibility that outlive any individual.”

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FERC Orders ‘Paper’ Hearing on PJM FTR Collateral Dispute

FERC ordered a “paper” hearing Tuesday to determine whether it should require a 99% confidence level in setting collateral requirements for financial transmission rights traders or the 97% level that PJM and most of its stakeholders have sought.

The commission accepted and suspended PJM’s proposed tariff revisions subject to refund. It issued an eight-page list of questions to be answered, saying that the evidence provided thus far failed to address its concerns that PJM’s requirements may be insufficient to protect stakeholders against losses (ER22-2029, EL22-32).

On Feb. 28, FERC rejected PJM’s proposal to modify the FTR credit requirement with an initial margin calculation from a historical simulation model (HSIM) using the 97% confidence interval, saying the RTO failed to support its proposal because its independent auditors validated the model at a 99% confidence interval. It directed PJM to make a filing within 60 days to show cause why its existing FTR credit requirement remains just and reasonable or explain what tariff changes will remedy the commission’s concerns (ER22-703). (See FERC Rejects PJM’s FTR Credit Requirement Proposal.)

At the Members Committee meeting March 23, stakeholders endorsed a motion for PJM to refile the original proposal “accompanied by some new supporting rationale.” The motion received a sector-weighted vote of 3.9 out of 5 (78%). (See Stakeholders Encourage PJM to Defend FTR Filing.)

Supporters of the filing said PJM credit revisions had demonstrated a significant drop in the failure rate of FTR portfolios and a reduction in potential collateral shortfalls.

But the Organization of PJM States Inc. (OPSI) and the Independent Market Monitor said the 97% confidence interval was unsupported. The IMM said PJM failed to justify why it selected 97% when the International Swaps and Derivatives Association uses a 99% confidence interval in its HSIM.

Among the questions asked by the commission was whether, compared to the 99% confidence interval, 97% causes the PJM market and its customers to subsidize collateral for FTR market participants and exposes the entire PJM membership to potential default costs.

It also asked how structural differences between the PJM FTR market and exchanges regulated by the Commodity Futures Trading Commission might justify the use of a lower confidence interval.

In compliance with the order, PJM told stakeholders it would implement the new FTR credit requirement effective today, coinciding with the close of the 2023/26 FTR long-term auction bidding window that opened Monday.

The RTO said it will make any collateral calls required by the revised credit requirement Thursday, after the bidding window closes.

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California PUC Adopts Submetering for EV Charging

The California Public Utilities Commission on Thursday established the first program of its kind in the nation by adopting a submetering protocol to allow electric vehicle owners to be billed separately for charging at lower rates than the rest of their electricity use.

“Submetering makes EV charging cheaper and will help spur the growth of electric vehicles throughout the state,” Commissioner Clifford Rechtschaffen said in statement following the unanimous vote. “It’s a practical solution to one of the important barriers to widespread EV adoption.”

The program uses submeters embedded in charging equipment as a way to avoid having to install costly second utility meters in homes and locations where electric trucks and buses charge. The submeters can transmit electric-use data via Wi-Fi or cellular networks.

The CPUC’s decision affects customers of the state’s three large investor-owned utilities — Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — all of which offer special rates for EV charging.

The IOUs have run submetering pilot programs since 2014 at the CPUC’s direction. The pilot programs addressed issues such as the reliability and accuracy of submetering and how to store and transfer the raw meter data.

The decision excludes net energy metering (NEM) customers with rooftop solar because the utilities said they have no way to tell if their energy consumption, recorded by a submeter, comes from the distribution grid, local renewable generation or battery storage. The CPUC ordered additional study to find ways of allowing NEM customers to participate in submetering.

The commission adopted a two-year timeline for the IOUs to incorporate submetering into their billing systems.

“The submetering protocol is a fundamentally important means of accelerating the growth of electric vehicles,” the decision said. “The protocol reduces the cost of electric vehicle charging; consumers can avoid having to install a separate utility meter and can instead use the technology to have their electric vehicle charging measured and billed separately from their primary utility meter. Submetering thus promotes the adoption of electric vehicles, the deployment of vehicle-grid integration, and the realization of the corresponding electric grid benefits.”

California is by far the nation’s leader in EVs with more than 1 million on the road, roughly half those in the U.S. Rechtschaffen said that more than 16% of new vehicles sold in-state are now EVs.

Gov. Gavin Newsom issued an executive order in September 2020 requiring all new passenger vehicles sold in the state to be zero-emission vehicles by 2035 and included $10 billion in recent budgets to accelerate the transition.

The CPUC has authorized the IOUs to spend more than $1.5 billion on EV charging and to create menus of special rates for it so that charging it is less expensive than buying gas or diesel fuel.