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August 1, 2024

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NRDC Lays out Responsible Tx Expansion Recommendations

The U.S. must double the number of transmission projects permitted and built each year to meet its clean energy potential, the Natural Resources Defense Council said Wednesday in a report recommending ways to speed permitting rules to allow enough construction to meet midcentury climate goals.

“We also must double the rate at which we expand the transmission system and simultaneously shift to building large interstate transmission lines instead of the small local lines that are mostly added today,” said NRDC Senior Advocate Nathanael Greene, the report’s lead author.

The Inflation Reduction Act is a huge opportunity for the country to roll out renewable energy and make significant progress on cutting greenhouse gas emissions, while the heat and natural disasters this summer show that climate change is happening and must be addressed, Greene said in an interview.

“Those two things I think allowed people to put building things higher on their priority list,” he added.

Issues around permitting have been a major focus for those working on federal energy policy all year, but so far, Congress has passed only a small package that largely ignored transmission. (See Lawmakers, White House Promise More Work on Permitting After Debt Deal.)

It is unclear whether lawmakers will be able to come up with another legislative package, but given the limited time due to the need to fund government operations and election season kicking into gear, NRDC wanted to express views on the subject to help inform any potential legislation, Greene said.

“This is an important conversation for Congress to be having because if a window opens, that’s not going to be open for long, and people need to know what’s important, what to do, what not to do,” he said. “Because it’ll have to happen quickly when it happens.”

A deal could be attached to some kind of must-pass bill this year, which would leave little time for members to examine the legislation, he added.

The report identifies four major barriers to getting needed transmission built, the first being the need to obtain federal authority to site, permit and allocate costs for large interstate lines while increasing community engagement.

FERC and the Department of Energy should work quickly to implement their strengthened authority to designate new “national interest transmission corridors,” the report said. (See States, RTOs Caution DOE on Transmission Corridors.)

NRDC is critical of FERC’s “rubber stamping” of natural gas pipelines, so it wants the agency to do more robust environmental reviews and provide stronger landowner protections when it comes to expanding the electric grid under its limited siting authority. While NRDC has litigated some of FERC’s implementation of the Natural Gas Act, that same kind of “bright line” siting authority would help expand the grid, Greene said.

“As long as it’s a political question about whether they’ll use that authority, it’s always going to be harder for them to do that permitting,” he added.

Ultimately, Congress should pass a law giving DOE authority to plan and FERC the ability to site large, interstate transmission lines, the report said.

Given that many of the projects NRDC wants to see built will cross state lines, having federal agencies planning and siting them makes sense, Greene said.

Another major recommendation is for FERC to “consider all the benefits of transmission” and then allocate them based on who benefits. The commission can implement rules to broadly allocate costs of new transmission to states, but if it fails to do so, then Congress should pass legislation requiring that, the NRDC said.

A pending notice of proposed rulemaking would update FERC’s planning and cost allocation rules. And while Chairman Willie Phillips has called that a priority, it has yet to pass.

Dealing with NIMBY

The report’s second recommendation is meant to deal with the opposition transmission projects often encounter because people do not want major infrastructure built near their homes, but that can be minimized by making community engagement a pre-requisite to siting rather than an afterthought.

“We know all the pieces of doing permitting better,” Greene said. “We just need to integrate and hold people accountable.”

The report suggests ensuring that communities gain benefits from hosting clean energy infrastructure. Specific benefits would vary by project, but they include jobs, environmental protections, financial contributions and energy benefits.

“Some developers already routinely negotiate community benefit packages for their projects,” the report said. “States should incentivize or require this as a best practice.”

The Inflation Reduction Act also earmarked money to help beef up permitting regulators in the states so they can adequately review the expanded pace of transmission development, Greene said.

The report’s third recommendation is to improve federal coordination, accountability and staffing of clean energy permitting and environmental reviews. That can be done without undermining the purpose behind the National Environmental Policy Act, the report said.

“Environmental reviews can be made much more efficient through increased agency resources, greater use of programmatic reviews, and permitting solutions that are tailored specifically to clean energy projects,” the report said.

The final recommendation is to embrace “smart from the start” planning to ensure that clean energy projects deliver conservation benefits and mitigate the impacts. That involves early and robust stakeholder engagement, planning at a landscape level, conservation of lands with important natural resources and cultural values, and moving projects to “low-conflict areas.”

“‘Smart from the start’ is designed to make permitting more efficient and to protect high-value lands by strategically focusing on regional or landscape-level efforts to mitigate the impact of renewable energy resources,” the report said. “These larger mitigation efforts often produce greater conservation outcomes than disparate project-level mitigation.”

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Report: Many US Utilities not Delivering on Energy Efficiency

Eversource Massachusetts scored 85 out of 100 points, taking the No. 1 spot on the American Council for an Energy Efficient Economy’s (ACEEE) 2023 Utility Energy Efficiency Scorecard, while Florida Power & Light and Ohio Edison held down the bottom of the list with 3 and 2.5 points respectively.

Published every three years, the recently released scorecard reflects the uneven, inconsistent role that energy efficiency plays in U.S. utilities’ efforts to decarbonize their power supplies, help customers cut their monthly energy bills and make their systems more resilient. The 53 utilities ranked on the scorecard, some of the nation’s largest, serve about 79 million residential customers, or 60% of U.S. households, in 31 states, the report says.

With their “enormous customer bases and the ability to scale solutions … the utility sector is perhaps the best positioned of any sector to deliver energy savings to Americans,” said Mike Specian, ACEEE’s research manager and lead author of the report. But, the scorecard shows, many are not doing so.

At the top of the list, 16 utilities managed to earn more than 50 points, and at the bottom, 16 earned less than 25.

Based on 2021 data, the scorecard shows investments in and energy savings from utility efficiency programs trending downward, Specian said. Total energy savings across all 53 utilities were 18.7 TWh in 2021, a 5.4% decrease since ACEEE’s last utility scorecard in 2020, which was based on 2018 data.

Utility spending on efficiency totaled $7.6 billion in 2021, a 4.9% drop from 2018, which, ACEEE said, contributed to a 19% drop in peak demand reduction. On average, U.S. utilities are spending 2.23% of their revenue on efficiency programs.

The figures for individual utilities underline the negative impact of these trends. Entergy Louisiana (No. 43, with 17 points) spent 0.21% of its revenue on energy efficiency, less than one-tenth of the national average. As a result, the utility’s energy efficiency programs shaved a meager 0.1% off its energy sales.

The caveat on such figures, and the rankings in general, is that they are based on data from 2021 and therefore may not reflect any changes in efficiency programs utilities might have made since then. In particular, as load management technology ― like smart thermostats ― evolve, lines between efficiency and demand response are starting to blur.

David Jacot, director of efficiency services at the Los Angeles Department of Water and Power (LADWP), said the public power utility recently consolidated its efficiency, DR and distributed energy services as part of its aggressive efficiency goals, a development not reflected in the scorecard.

But, Specian cautioned, most utilities are not connecting their energy efficiency programs to their decarbonization or emission-reduction goals. “In fact, 28 of our 53 evaluated utilities have established some form of carbon-reduction goals, [but] those targets have yet to work their way into efficiency programs,” he said.

Only the two Massachusetts utilities, Eversource Energy and National Grid, have “explicitly incorporated [greenhouse gas] reduction goals into their energy efficiency programs,” he said.

If and to what extent the billions in funding for energy efficiency in the Inflation Reduction Act will affect utility programs remains uncertain, in large part because, like other IRA programs, the incentives and rebates for efficiency have been slow to roll out.

The IRA’s $8.5 billion for rebates and tax credits for energy-efficient home upgrades will be administered by the states, and the U.S. Department of Energy only recently opened the application process for states to submit plans on how they will ensure the money is used to cut consumer energy bills and emissions. (See DOE Opens Applications for $8.5 in IRA Home Efficiency Funds.)

Utilities could have a central role in these programs for raising customer awareness of the IRA rebates and incentives. Many utilities already offer rebates on efficient appliances and promote their expertise as “trusted advisers” for customers considering home upgrades.

State Regulation

Downward trends notwithstanding, during a recent webinar on the scorecard, Specian focused on the report’s more encouraging findings, such as the correlation between state energy efficiency mandates and utility performance, and increasing investments in efficiency programs for low-income customers.

Utilities at the top of the list, as well as those that shot up in the rankings, often are in states that have set targets for utility efficiency programs.

Michigan, for example, passed its first energy efficiency law in 2008, requiring utilities to meet specific savings goals, and then upped the targets in 2016. Home-state utilities DTE Energy and Consumers Energy have exceeded those mandates every year, putting them in the scorecard’s Nos. 5 and 6 spots, respectively.

Dominion Energy was the scorecard’s most-improved utility, jumping from No. 50 in 2020 to No. 27 this year. Specian attributed its better performance, in large part, to efficiency goals set in Virginia’s Clean Economy Act, passed in 2020.

At the same time, rankings for Ohio utilities nosedived this year after the state legislature passed a law in 2019 ending its energy efficiency standards. Duke Ohio and AEP Ohio fell from No. 18 and No. 21, respectively, to tie for No. 49 this year. Ohio Edison tumbled from No. 34 to the very bottom of the list.

State mandates also can act as a brake on utility innovation. Public Service Electric and Gas rose from No. 42 in the 2020 rankings to No. 25 this year, largely because of New Jersey’s efficiency targets. But Susanna Chiu, PSE&G director of energy services, said regulations set by the Board of Public Utilities create a three-year cycle for planning new utility efficiency programs.

The current cycle, which runs through June 30, 2024, did not include decarbonization or more innovative DR programs. Those will have to wait for the next three-year planning cycle, which will run from mid-2024 to mid-2027, Chiu said. PSE&G is envisioning a one-stop-shop approach in which customers can choose efficiency services that are customized for their homes and their own efficiency and decarbonization goals, she said.

Low-income Programs

Total utility spending on efficiency may have dropped, but the money spent on programs for low-income customers has grown to more than 12% of overall efficiency spending — a 17% increase since the 2020 report — resulting in an 9.5% increase in savings per residential customer, Specian said.

Digging in deeper, ACEEE added new categories on equity to this year’s scorecard, which revealed some of the gaps that still exist in efficiency programs for low-income customers. Baltimore Gas and Electric dropped from No. 5 in 2020 to No. 12 this year, after losing points on some of the new equity categories.

In a separate, written analysis of the utility’s score, Specian praised BGE for its innovative program offerings, including “12 valuable efficiency programs not commonly available across the rest of the country.” Yet the utility lost points for “a lack of efficiency workforce initiatives, low levels of community engagement during program development and a failure to direct customers at risk of utility shutoff toward efficiency programs that could lower their bills,” he said.

Speaking during the webinar, Sanya Carley, professor of energy policy and city planning at the University of Pennsylvania, said efficiency programs can be a critical tool in helping low-income customers avoid disconnection.

A 2020 report from ACEEE found that low-income households have a heavier “energy burden,” spending 8.1% of their disposable income on energy versus the 2.3% for more well-off households.

Only 13 utilities on the scorecard direct customers at risk of disconnection to efficiency programs, Carley said, and existing efficiency programs may not address the needs of such “energy insecure” households. Living in an energy-inefficient home ― with gaps in walls, or windows that don’t close ― is one of the factors that may signal risk of disconnection, she said.

Carley has collaborated with researchers at the University of Indiana to launch an online Utility Disconnection Dashboard, tracking disconnections across the country.

“Some of the same utilities that have the highest rates of disconnection are the ones not directing their customers toward energy efficiency,” she said. “Does this mean that energy efficiency programs are too late to help or too little? The data don’t reveal answers to these questions, but we should of course ask them.”

Efficiency After LEDs

While it was not part of individual rankings, ACEEE did ask utilities what they see as major barriers to energy efficiency.

Responses ranged from the predictable ― inflation, supply chain delays and lack of skilled workers ― to the more existential, such as the rising cost of efficient technologies once programs address “low-hanging fruit,” such as switching out older light bulbs for LEDs.

“Utilities that have been successfully implementing energy efficiency for years reported experiencing market saturation for some efficiency measures and decreasing amounts of remaining savings,” the report says. “Others claimed that there was no technology that could easily fill the gap left by lighting.”

Lakin Garth, director for emerging technologies at the Smart Electric Power Alliance (SEPA), agrees some utilities eventually may face a declining stock of buildings to retrofit.

“You’ve got a certain number of buildings out there, and you’re acquiring all the most cost-effective energy efficiency over a three-, four- or five-year period. … Those same opportunities might not be there in six or seven or eight years,” Garth said. “But that doesn’t mean that the investment itself should decline.”

According to the National Association of Home Builders (NAHB), close to half of all homes in the U.S. were built before 1970 — before the first energy efficiency codes were passed later in the decade. California’s first energy efficiency code was adopted in 1976 and is updated every three years.

Given the large opportunity the NAHB figures represent, Vincent Barnes, senior vice president of policy and research at the Alliance to Save Energy, says the key obstacles to utility energy efficiency programs are utility regulation and business models.

“We don’t treat energy efficiency at par with other energy resources that utilities can respect as an asset,” Barnes said. “It really is about looking at energy efficiency as an energy resource and therefore identifying energy efficiency investments as capital investments — like transmission, like distribution — and the reason we have to do that is because the way the structure is currently set up, the only assets are supply-side assets.”

Energy efficiency programs address customers’ consumption behind the meter, he said. “It’s not until we’re able to identify those investments that are behind the meter, and energy efficiency also, as capital assets, [that we will] be able to actually achieve that greater investment number that we might be looking for.”

One encouraging development, Barnes noted, is that PSE&G has gained approval from the BPU to treat at least some of its energy efficiency investments as “regulatory assets” that can be included in the utility’s rate base.

Chiu confirmed that such efficiency investments do “earn a return … which makes those investments an alternative to pipes and wires.”

LADWP’s ‘Headroom’

In the No. 10 spot, LADWP is the highest scoring of the three public power utilities on the ACEEE scorecard. The other two are Long Island Power Authority (No. 16) and the Salt River Project (No. 23).

As an unregulated utility, LADWP has been able to approach efficiency from a totally different angle, Jacot said. “We really got in earnest behind energy efficiency around 2010 and made it a part of what we call our supply portfolio,” he said. “In other words, we treat energy efficiency as a generation resource … the cheapest marginal generation resource.”

Between 2010 and 2020, the utility cut its retail kilowatt-hours by 15% and is on track for another 15% cut by 2030, Jacot said, and those savings have created “headroom” for LADWP to absorb new load without building new generation.

Vehicle electrification is a case in point. As the utility’s customers plug in their Teslas and Ford F-150 Lightnings, “we’ve created the headroom through energy efficiency; that capacity is already there,” he said.

LADWP will have to build out its system eventually to meet the demands of widespread electrification and more frequent and intense heat waves, but the utility’s aggressive efficiency programs have bought it some time, he said.

Jacot stressed the ability of public power utilities like LADWP to innovate and try out new programs quickly, without going through the drawn-out regulatory approval process investor-owned utilities typically face. With the integration of LADWP’s efficiency and DR programs, Jacot is overseeing and exploring new possibilities for both programs.

“I can coordinate not only overall energy use reduction but smart energy management and load-shifting capabilities,” for example, using smart thermostats and heat pump water heaters, he said.

Heat pumps can be set at a variable speed to reduce overall consumption, and then set to run at specific times of the day for DR, he said.

Like PSE&G, LADWP’s goal is to have a one-stop-shop for customers to take advantage of both efficiency and DR programs, he said.

Next-gen Efficiency

Today’s energy efficiency programs trace their roots to the 1973 oil crisis, when the Middle Eastern countries in the Organization of Petroleum Exporting Countries slapped an embargo on exports to the U.S. to protest American support for Israel.

Efficiency then meant closing schools and businesses, rationing gasoline and reducing speed limits on the nation’s highways to 55 mph.

The challenges today are technologically more complex but could be equally essential to President Joe Biden’s goals of decarbonizing the grid by 2035 and building out a net-zero economy by 2050.

At LADWP, Jacot sees the value of efficiency evolving in different directions as solar and storage come on the grid.

“We’re in a transitionary period where energy efficiency at some points of the day actually doesn’t do you much good,” he said. Specifically, during mid-day peaks in solar production, “energy efficiency isn’t really helping. … So, the quantification of the benefits of energy efficiency on the demand side, the kilowatt side, is very much in transition.”

However, Jacot said, as more storage is deployed to sop up excess solar production, and electrification drives more demand for power, LADWP will “want all the energy efficiency we can get because it increases the amount of available storage and lowers the amount of storage you need to get through the night.”

SEPA’s Garth also sees efficiency as essential for maintaining reliability and affordability as the grid is decarbonized and transportation and buildings are electrified.

“If we’re electrifying or planning to electrify all these uses, then these utilities should be thinking about how to do that in the most efficient way possible,” he said. “Probably the next generation of efficiency programs is how do we electrify responsibly and efficiently and how do we identify the parts of the market that have been overlooked in the past?”

But producing the clean power needed for electrification will require significant capital investments, which utilities could seek to recover through higher rates, he said. “So, it only seems logical that in a decarbonized world … the investments made in energy efficiency are commensurate with the investments that are made to clean up generation or to reduce carbon emissions.”

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Wash. Allowance Prices Surge Again in 3rd Cap-and-trade Auction

Washington carbon prices continued to rise last week after the state’s latest cap-and-trade auction cleared at $63.03, up 13% from the May auction.

The August auction represented the third quarterly sale of allowances by the state, raising roughly $542 million in revenue on 8.6 million allowances sold, according to the Washington Department of Ecology. That translates into about $1.462 billion raised so far this year, with one regular quarterly and one supplemental auction still to go.

Washington Carbon Allowance (WCA) prices have risen steadily with each auction, with the February sale clearing at $48.50 and May’s hitting $56.01. The cap-and-trade program went into effect on Jan. 1, 2023.

“Prices at quarterly auctions are determined by auction participant behavior, so we can’t really speculate as to why bidding has resulted in any increasing settlement prices,” Claire Boyte-White, Ecology’s policy relations manager on cap-and-invest issues, said in an email to NetZero Insider.

“Because our program is still new, one potential explanation is that market participants are still getting their feet under them as they develop their compliance and decarbonization strategies” Boyte-White wrote.

In a summary of the auction results, emissions markets analytics company cCarbon noted that both the California cap-and-trade and Regional Greenhouse Gas Initiative markets saw prices peak during their third auctions before pulling back from those highs.

“Only time will tell if Washington’s WCAs will follow a similar trend!” cCarbon said.

The company also pointed out that financial traders increased their takings in Washington’s most recent auction, winning 14.5% of allowances compared with 10% in the previous auction.

“This increase, coupled with a lower bid ratio of 1.79, strongly suggests that compliance entities are content with their current holding at these price levels,” cCarbon said.

High allowance prices have been blamed for Washington having the highest gasoline prices in the nation this summer, outpacing even California, the only other state with a cap-and-trade program. (See Cap-and-trade Driving up Washington Gasoline Prices, Critics Say.)

Washington officials have been exploring whether the state should link up with the California-Quebec cap-and-trade system as a way to reduce prices, and hope to make a decision this year. That combined market is roughly six times as liquid as Washington’s, with allowance prices hovering at about $35.

Last week’s WCA auction once again exceeded the soft cap of $51.90 that triggers a requirement to hold a supplemental Allowance Price Containment Reserve (APCR) auction, a mechanism intended to contain carbon costs for industry by releasing more allowances into the market. The first APCR auction held in early August raised about $62.5 million on 1,054,809 allowances sold. (See Wash. Raises $62.5M from Cap-and-trade Reserve Auction.)

The next APCR auction is scheduled for Nov. 8 and will offer 1.58 million allowances.

“We anticipate that these extra APCR allowances will moderate prices in the short term,” cCarbon said in its summary. “Indeed, we are already seeing signs of this impact on the prices and demand from compliance entities in this third WCA auction.”

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Mass. Utilities Submit Grid Modernization Drafts

Eversource and National Grid expect their annual peak electricity load in Massachusetts to more than double by 2050, the utilities told the state’s Department of Energy Resources (DOER) last week.

The projections are part of the draft electric sector modernization plans (ESMPs) submitted to DOER by Massachusetts’ investor-owned electric utilities, which detail the electric distribution companies’ plans to meet the massive increase in electricity demand associated with the electrification transportation and heating in the state.

The wide-ranging drafts also include near-term investment proposals, five- and 10-year demand forecasts and solutions planning, and they mark a major change in how the state conducts grid planning.

The Grid Modernization Advisory Council (GMAC), a stakeholder committee created by the state’s 2022 Act Driving Clean Energy and Offshore Wind and convened by DOER, will review the filings, solicit public feedback and provide comments on the utilities’ drafts.

“It’s really taking a forward-looking approach for the first time in Massachusetts’ history,” said Kyle Murray, Massachusetts program director for the Acadia Center and GMAC voting member. Murray said grid planning in the state historically has happened in an “ad hoc manner.”

Murray added that one of the council’s goals is to engage the public in the grid modernization process and include voices that historically have been absent from these proceedings.

The draft ESMPs outline the large infrastructure investments that will be needed to enable the clean energy transition, including huge increases in peak electrical loads. National Grid expects its annual peak to increase from about 4.6 GW to 10.7 GW.

National Grid 2025-2029 proposed ESMP investments | National Grid

“Annual peak load, which is the maximum demand on the system in a given year, is expected to grow across our network 7% by 2029 and 21% by 2034 relative to 2022 levels, and more than double by 2050,” National Grid wrote in its 726-page report.

Eversource expects an even larger increase for its system, anticipating its peak to rise from about 6.1 GW to 15.3 GW.

“The majority of this 150% increase in electric demand by 2050 is driven by electrification of heating needs (about 50%) with the remaining driven primarily by electrification of transportation needs (25%) and normal load (25%),” Eversource wrote.

The utilities also noted that the increasing reliance on distributed energy resources (DERs) will further strain the grid and necessitate additional upgrades.

To meet the expected demand increases, Eversource proposed building 12 new substations and upgrading 16 existing substations. The company also proposed three new substations and 14 upgrades to accommodate additional solar resources. National Grid proposed upgrading or expanding 18 existing substations and building 28 new substations by 2034.

“Absent making these system investments in advance of these new peak demand levels, the expected load growth will result in overloads of existing equipment, which would impact the safety and reliability of our network operation,” National Grid wrote.

National Grid peak load forecasts | National Grid

Murray said one of his main hopes for the process is to help clear out the interconnection backlog of renewable energy projects.

“We know we need as many renewables on the market as possible, and yet they’re coming on at a pace that’s kind of like a trickle,” Murray said.

“Building system capacity with substations and battery storage systems will provide a critical foundation for enabling electrification and reliable interconnection of DERs,” Eversource wrote.

The utilities emphasized the importance of early public engagement while making these investments, and jointly proposed the creation of a Community Engagement Stakeholder Advisory Group (CESAG) to help boost engagement with potentially impacted communities. Under the utilities’ proposal, the group would be led by the utilities, with members agreed upon by the GMAC.

Eversource 2025-2034 proposed capital investments | Eversource

In an August letter to the GMAC, María Belén Power, undersecretary of environmental justice and equity at the Office of Energy and Environmental Affairs, stressed the importance of including environmental justice communities in the infrastructure siting process.

“[Environmental justice] populations should be engaged in public processes from the very beginning, not as an after-thought, and the engagement must be coupled with meaningful outcomes and results,” Power wrote. “Adding equity or community outreach as a final step in the process does not allow for a meaningful process. Successful community outreach happens when the voices and perspective of those most vulnerable are reflected in the outcome.”

Power said all communities affected by new grid infrastructure should be given ample opportunity to participate in siting processes, with accommodation made for the different languages spoken by residents. The undersecretary also emphasized the importance of considering the cumulative effects of grid infrastructure.

“When planning for new energy infrastructure or enhancement of existing ones, we must ensure we are not causing additional harm to those who have historically been overburdened,” Power said. “When possible and if feasible, if a project may cause additional harm or burden on EJ populations, an alternative site should be identified.”

The utilities also outlined some mechanisms to reduce future demand, including energy efficiency, advanced metering infrastructure, managed charging and time varying rates.

“Regulatory and tariff changes that enable time-varying rates and recognize the shift toward greater electrification are required to support more impactful offerings to offset peak demand growth with increasingly flexible loads and expanded deployment of distributed resources,” National Grid wrote.

Larry Chretien, executive director of the Green Energy Consumers Alliance and a GMAC member, told RTO Insider he still is reviewing the drafts, but agreed on the need to develop programs like time-varying rates and managed charging focused on reducing peak demand. High demand peaks lead to both higher costs for consumers and increased fossil fuel combustion.

“We think it’s sacred that we’ve got to reach our climate goals, but we also want to make sure that it can be afforded by folks who are economically vulnerable,” Chretien said. “I want to push the utilities on trying to bend the demand.”

The GMAC will hold public listening sessions Oct. 30 and Nov. 1, with final feedback and recommendations from the GMAC due Nov. 20. The utilities then must file their final ESMPs with the Department of Public Utilities in January.

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Stakeholder Soapbox: The Cost of Inaction — An Outdated Grid, Overpriced Power

Jason Stanek | Maryland PSC

By Jason Stanek

The nation has a looming problem. The infrastructure upon which millions of Americans rely on to power their daily lives is growing older while demand on regional power grids is breaking all-time records with increasing regularity. The country’s regional grid operators lack sufficient access to generation in neighboring regions, resulting in preventable power outages and soaring electricity prices during extreme weather events. Even under normal operating conditions, a lack of import and export capability between various parts of the country can result in higher power costs.

The construction of high-voltage transmission lines between regions has been stymied over the years for various reasons, but it is clear we increasingly need new interregional lines, both now and in the future. One relatively simple way to accomplish this would be for Congress to direct FERC to establish a minimum interregional transfer capacity requirement to ensure that grid operators have enough capacity to export or import a certain amount of power to neighboring regions at all times. Doing so will strengthen the nation’s resilience to extreme weather events, increase overall grid reliability and ultimately reduce the cost of delivered electricity to customers.

Fortunately, this policy option has recently been the focus of significant discussion by stakeholders. Late last year, FERC discussed such a minimum transfer standard. Notably, in its post-workshop comments, the U.S. Department of Energy emphasized that its draft National Transmission Needs Study finds a “pressing need for additional electric transmission infrastructure, including interregional transmission.” Additionally, this topic has merited review by the Joint Federal-State Task Force on Electric Transmission, a collaborative dialogue between FERC commissioners and state utility regulators.

So, what’s the “right” amount of transfer capacity? Some grid experts have called for a minimum interregional transfer capacity requirement ranging from 15 to 30% of peak load. While there are benefits and costs associated with a higher or lower percentage, there is wisdom in setting a uniform minimum requirement. As I recently testified before the Senate Energy and Natural Resources Committee, it would be more expeditious if Congress were to define and set a reasonable threshold rather than tasking FERC with a multiyear stakeholder process to determine the requirement, a process that would surely further delay critical projects’ buildout.

The need for new transmission lines also serves to mitigate the impact of extreme weather events, which are undeniably increasing in severity and frequency. In the first seven months of this year, 15 extreme weather events across the country — several of which caused power outages — each resulted in $1 billion or more in damages. These events accounted for the most disasters over the period since 1980. Extreme weather has also contributed significantly to congestion costs in recent years. While power outages during storms are never fully preventable, we can prepare our electric grid to better withstand them, as interregional transmission lines can transport available power from several states away to areas where local generators cannot meet demand.

Further, as I testified, long-distance wires connecting regions serve as an important insurance policy: While grid operators hope to avoid asking neighboring grids for electricity, it is important to have the ability to do so when a situation arises. For example, the addition of high-capacity interregional transmission lines from Texas to neighboring regions could have prevented the devastating storm-induced outages in February 2021, according to an analysis from power sector consulting firm Grid Strategies. Given the tremendous cost savings associated with additional interregional transmission capacity, a line could have paid for itself in four days during that cold snap.

More recently, some utilities could have saved upward of nearly $100 million per gigawatt of capacity in late 2022 if they were able to wheel more power in from the Midwest or New York. Instead, unplanned generation losses of all types exceeded 70 GW, and several balancing authorities ordered firm load shed of more than 5 GW over the Christmas holiday.

Moreover, increasing congestion on the regional power grids — when there is insufficient transmission capacity to deliver the most affordable power to customers, forcing more expensive generating units to run — cost the U.S. an estimated $20.8 billion in 2022, according to Grid Strategies. While this savings estimate can be debated, it is indisputable that customers pay more when they are unable to access cheaper supplies of electricity.

These facts are not lost on utility regulators. During the past year, members of the federal-state transmission task force reviewed the merits of a minimum transfer capacity standard and, more broadly, the need for more interregional transmission. In an op-ed published by RTO Insider in April, former Arkansas Public Service Commission Chair Ted Thomas touted the “significant reliability benefits” a standard would provide. (See Stakeholder Soapbox: Transmission Keeps the Lights On.)

At a task force meeting, former FERC Chair Richard Glick recognized that over the last decade, “there really hasn’t been any interregional transmission built … so we’re in a situation where I believe we need to consider, are there reforms that are necessary to move forward?”

Vermont Public Utility Commissioner Riley Allen found that there is a “growing body of evidence [that] interregional transmission can contribute to a significant degree on a triad of needs,” including affordability, reliability and clean energy. And Dan Scripps, chair of the Michigan Public Service Commission, similarly emphasized that “there’s no doubt that increased interregional transfers and interregional transmission can also offer additional benefits, particularly economic benefits, but ultimately the real value is ensuring that we have a grid that can support reliability and enhanced resilience, particularly in times when the grid operates in ways other than for which it is originally planned.”

I agree with my colleagues on these points, but I also know that the cost of developing new energy infrastructure projects must be weighed against a number of competing considerations. That said, I am confident that building more interregional transmission lines is a good, near-term investment that will deliver benefits now and for future generations. The facts are clear; it’s the political will that is needed.

Jason Stanek is the former Chairman of the Maryland Public Service Commission and previously served as a co-chair of the Joint Federal-State Task Force on Electric Transmission.

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Settlement Possible Between PJM And Several Generation Owners over Winter Storm Complaints

Several generation owners and PJM are progressing toward an agreement regarding the non-performance charges the RTO assessed in its allegation the generators failed to meet their capacity obligations during the December 2022 winter storm, according to the settlement judge mediating the deliberations (EL23-53, et al.).

Judge Matthew J. Vlissides Jr. wrote in a Sept. 1 status report that a “majority of the participants indicated that they reached a settlement in principle” as of the previous day’s conference and he recommended terminating the process without holding further meetings. (See FERC Sends Elliott Complaints Against PJM to Settlement Judge.)

“These participants represent that they are finalizing the settlement materials and anticipate filing the settlement package by late September 2023,” he said.

East Kentucky Power Cooperative spokesperson Nick Comer said EKPC is pleased the parties have reached a settlement in principle but wouldn’t comment further until the terms have been filed with the commission. PJM declined to comment.

The companies involved in the settlement procedures include Essential Power (EL23-53), Aurora Generation (EL23-54), the Coalition of PJM Capacity Resources (EL23-55), Talen Energy (EL23-56), Lee County Generating Station (EL23-57), SunEnergy1 (EL23-58), Lincoln Generating Facility (EL23-59), Parkway Generation Keys (EL23-60), Old Dominion Electric Cooperative (EL23-61), Energy Harbor (EL23-63), Calpine (EL23-66), Invenergy (EL23-67) and EKPC (EL23-74).

PJM stated the penalties from Winter Storm Elliott total about $1.8 billion, though during stakeholder meetings it has said it’s likely some percentage of generators will default on the penalties. To reduce the impact to those companies, PJM filed to extend the payment period for non-performance charges to nine months, which FERC approved in April. (See “FERC Approves Alternative Billing Schedule,” PJM: Elliott Nonperformance Penalties Total More Than $1.8B.)

The commission established the settlement judge procedure June 5 to see if the parties involved in a dozen complaints could reach an agreement within 60 days and extended the process an additional month on Aug. 14 after Vlissides wrote a progress report finding the parties were “significantly progressing” toward settlement.

PJM asked the commission to establish a settlement judge in April, arguing that while it maintains the penalties are valid, a faster resolution could support the long-term health of the capacity market and result in more consistent settlement outcomes.

“The capacity market also is designed in large measure to signal the need for new capacity resource investment, and the expectations of the financial and investment community accordingly are an important backdrop to the operation of this market,” PJM said in its earlier filings. “Timely, consensual resolution of these disputes thus could, potentially, help support the long-term health of the resource adequacy construct in the PJM region.”

The complaints argued PJM improperly declared emergencies in regions where it was not warranted and continued to export to other balancing authorities in contravention of its tariff and the RTO had not provided generators with the required notifications they were expected to be available to allow them to procure fuel.

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Overheard at Infocast Texas Clean Energy Summit

AUSTIN, Texas — The Infocast Texas Clean Energy Summit attracted several hundred developers, asset owners, financiers, investors and ERCOT stakeholders to discuss the booming opportunities and looming challenges in today’s renewables environment.

Speakers and panels discussed large flexible loads, crypto mining, energy storage, Texas’ continued reliance on renewable energy and the challenges facing ERCOT from the state’s tremendous growth and insatiable demand for energy. Many of those solutions will be affected by the new laws and rules passed by the recent Texas Legislature.

Part of a panel addressing the new legislation, Mark Stover, director of state affairs for Apex Clean Energy, pointed to a projected slide that included images of a couple of news clippings.

“Clean energy escapes the legislative session,” he said, referring to one of the headlines mentioned. “That’s fairly accurate. Did we lose any limbs? We did not.

“I think there were about 50 bills that impacted our industry, but there were 19 bills that did not get across the finish line. Some were killed on the floor, some never got on a hearing, others kind of just got lost in the shuffle. But there were 19 bills that would have directly harmed the clean energy industry. Fortunately, those went away.”

Mark Stover, Apex Clean Energy | © RTO Insider LLC

One of the bills that failed (Senate Bill 624) would have required wind and solar facilities to acquire special permits from the PUC, a requirement thermal generators wouldn’t face.

“That was an industry killer that would have been absolutely devastating for the clean energy industry,” Stover said. “Fortunately, we were able to get the recession and ensure that that bill did not pass, no trouble.”

Still up in the air is the shape of the future ERCOT market. The grid operator and the state’s regulators still are pushing forward with the performance credit mechanism (PCM), a market tool that would retroactively reward dispatchable generation that meets performance criteria during the tightest grid periods with incentive payments.

Staff plans to draft a strawman proposal incorporating the Public Utility Commission’s feedback and hold a series of workshops with stakeholders and PUC staff. ERCOT and the market monitor will perform a cost-benefit analysis before the legislature next meets in 2025. The ISO expects it will take another two years to implement the PCM.

“So where do we go from here? There’s a lot of details to be worked out,” said Nate Miller, a director with Energy and Environmental Economics (E3). (The firm studied several market designs for the PUC but did not recommend the PCM.)

He said a reliability standard first must be determined, as it will set the PCM’s performance credits awarded to generators. Then comes the question of dispatch requirements, hybrid resources only being part of the equation.

“There’s a lot of details in the PCM that could significantly weigh the impact of PCM on the market,” said Resmi Surendran, vice president of regulatory policy for Shell Energy North America. “The PCM, based on some studies, could have been a one-third reduction in the energy price, which is the revenue stream for renewables. Hopefully, it can be implemented as an additional revenue stream … without reducing the revenue stream for everyone else.”

Shell Energy’s Resmi Surendran lays out the current state of the ERCOT market as moderator Matthew Boms takes notes. | © RTO Insider LLC

Investors Cautious After New Laws

While the renewable sector may have escaped more severe legislation this year, it may have been enough to scare off some potential investors.

“Investors saw what happened in that last Texas session and are sort of unsure about what’s going to happen in the next session for understandable reasons,” said Frank Swigonski, director of market design for Pine Gate Renewables. “I’ve heard people say that there’s always been anti-renewable sentiment in Texas and this was just another day at the office. The difference last session was it was a little bit more pronounced and it got a little bit more national attention. I think that’s something that we’re going to be dealing with as we’re trying to get investment projects long term.”

Frank Swigonski, Pine Gate Renewables | © RTO Insider LLC

Swigonski said the PCM remains the biggest question mark with how costs will be allocated and its effect on the energy market.

“That uncertainty itself is a challenge because other developers can probably feel the same way and we can execute around new interconnections, cost allowances and new firming requirements, as long as we know what those requirements are,” he said. “But as long as there’s a big question mark in your financial spreadsheet, it’s really hard to close on them right.”

That said, Swigonski still says the Texas energy market is a great place to invest.

“The interconnection process in Texas is the fastest, the easiest and cheapest anywhere in the country. None of that changed,” he said.” Texas is a big state. It’s got a dynamic, dynamic economy, there’s load growth, low taxes, and there’s a lot of sunshine and wind.”

“We’re pretty invested in Texas, and we think that the policy risk is very manageable,” said Allan Schurr, chief commercial officer of storage developer Enchanted Rock. “I can tell you that having lived a former life in California that it is a wild card. Texas is a lot more predictable. It’s undergoing a lot of changes with the market redesign. I don’t know about the fundamentals but somehow, through the noise and the fog, there’s still opportunity for us.”

Living with Large Flexible Loads

When Bitcoin miners — having been shoved out of China because of their insatiable demand for power — began flocking to Texas in 2021, Gov. Greg Abbott (R) welcomed them in a tweet proclaiming the state “will be the crypto leader.”

Two years later, Bitcoin mining consumes about 2.2 GW of power. That consumption could triple should the additional 4 GW of mining operations approved by ERCOT’s interconnection process become energized. And while the mining loads gobble power, their ability to shut down quickly during tight operations is what makes them appealing to grid operators.

ERCOT has adapted quickly to Bitcoin, data centers and other large, flexible loads (LFLs). It has created a working group dedicated to the loads and hired an LFL interconnection manager, Agee Springer. It also has proposed new LFL classifications as either curtailable load resources or registered curtailable loads; the former would participate in economic dispatch; the latter would operate outside SCED.

“The optimal solution for reliability would be for as many of these loads as possible to participate in the economic dispatch,” Springer said. “What this really does is it allows their behavior to be factored into the economic dispatch and accounted for when generation is instructed on how much power to produce. We see this as kind of a benefit to both loads and to ERCOT. It takes the guesswork out of being price responsive. You feed your desired behavior and your strike prices into the economic dispatch and then your behavior is coordinated with the rest of the grid.”

Agee Springer, ERCOT | © RTO Insider LLC

He said the proposed concepts, which could be ready next year, would provide more data from load resources and improve the accuracy of ERCOT’s forecasts. That would create a bigger pool of ancillary services, Springer said, “so that’s a benefit for everyone.”

Bryn Baker, Clean Energy Buyers Association | © RTO Insider LLC

The Clean Energy Buyers Association’s Bryn Baker, senior director of market and policy Innovation, stressed the need to be able to run a 21st-century grid that keeps the lights on in 21st-century weather.

“That requires thinking more expansively about what is dispatchable versus non-dispatchable. Certainly, renewables are not always reliable and the dispatchable energy is not always reliable,” she said.

“A big success story, besides demand response, is wind, solar and storage holding up the grid when its groaning at the edges,” Baker added. “It is going to require thinking about things differently. We’re going to need new technologies and new approaches … but most important is that we’re building [an ERCOT] market where that innovation happened, where testing those new technologies and approaches is possible.”

IRA Could Be Boon to Texas

Several panelists marked the one-year anniversary of the Inflation Reduction Act, which provides billions of dollars in incentives, grants and loans to support new investments in clean energy and other areas.

Matt Pawlowski, NextEra Energy Transmission | © RTO Insider LLC

“When you look at it at first blush, you see a lot of positive things that are more long term,” said Matt Pawlowski, vice president of development for NextEra Energy Transmission. “We’ve gone from the years of three to five years [of tax credit deadlines], etc., where you’re kind of rushing into everything because you think it’s going to expire. Now, we have a much longer runway … the IRA has been a longer-term view of things that we’ve wanted for years, instead of three-, four- and five-year chunks.”

George Hardie, vice president of business development for Pattern Energy Group, agreed the IRA will spur new development in Texas.

“It’s a mixed bag of theories and it’s certainly ample ammunition for issues in some of the congested areas in the Texas Panhandle, where there’s more power than can get to some of the load centers,” he said, noting the demand placed on the grid by oil and gas production in the Permian Basin. “We’re seeing astounding load growth … all that oil and gas is being electrified, so there’s going to be a significant amount of renewables and weather, as well solar, needed for that density.”

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9th Circuit Upholds FERC’s Revisions to PURPA Regulations

A federal appeals court on Tuesday rejected a challenge to FERC’s 2020 revisions to how it enforces the Public Utility Regulatory Policies Act, though it concluded the commission committed a “serious violation” by not conducting a formal environmental assessment (EA) before issuing the order (20-72788).

Multiple renewable energy industry and environmental advocacy groups petitioned for review of Order 872, which they argued made it more difficult for independent, non-utility-owned energy generators to be designated qualifying facilities under PURPA (RM19-15, AD16-16). (See FERC Rejects Challenges on PURPA Changes.)

The 9th U.S. Circuit Court of Appeals, however, found that FERC holds broad rulemaking discretion and its interpretations of the law were not unreasonable. The court also rejected the petitioners’ challenges to four specific provisions of the order.

The court did agree with the petitioners’ contention that FERC violated the National Environmental Policy Act by not preparing an EA before issuing the order. It remanded the order to FERC to conduct an EA, but it declined to vacate it.

“Although FERC’s failure to prepare an EA is a serious violation, Order 872 does not suffer from fundamental flaws, making it unlikely that FERC could adopt the same rule on remand, and the disruptive consequences of vacatur would be significant,” the court said.

PURPA directed FERC in 1978 to promulgate rules to encourage development of two types of QFs: alternative energy sources such as renewables owned by the same person within 1 mile of each other that totaled no more than 80 MW generation capacity, or fossil-fired cogeneration facilities.

The law mandated that electric utilities buy the power generated by QFs under rate guidelines established by FERC and set by states. In response, FERC issued Orders 69 and 70 in 1980.

Congress changed the statutory language via the Energy Policy Act of 2005, and FERC responded with Order 688, which among other things established a rebuttable assumption that facilities with not more than 20 MW capacity do not have adequate, nondiscriminatory access to markets.

With Order 872, issued under then-Chair Neil Chatterjee (R), the commission explained that extensive technology advances and dramatic energy industry changes in the preceding 40 years made significant revisions necessary.

Among other things, FERC:

    • expanded the 80-MW calculation radius to up to 10 miles and set a list of factors to establish whether facilities were “separate”;
    • allowed states to eliminate the fixed-rate option;
    • gave states additional flexibility to calculate utilities’ avoided costs; and
    • reduced the 20-MW nondiscriminatory threshold to 5 MW.

Ruling

The 9th Circuit rejected the petitioners’ contention that Order 872 discourages development of QFs, and therefore violates PURPA, which directed FERC to encourage such development.

The judges shot down various other arguments as well. They ruled that:

    • FERC did not overstep the authority granted to it by PURPA, and Order 872 meets the test of the Chevron
    • FERC was not arbitrary or capricious in making the rules; it was reasonable and used discretion delegated to it by Congress.
    • Order 872’s rate-related provisions do not violate PURPA’s nondiscrimination requirement.

The court did fault FERC for its reasoning for not preparing an environmental impact statement or an EA.

“FERC misunderstands NEPA’s requirements,” it wrote, adding that the commission’s own regulations for implementing NEPA support its conclusions.

“It was eminently foreseeable that a regulatory change of this magnitude could produce significant environmental effects,” it wrote. “It was a near certainty, for example, that at least some QFs could lose their status under the 2020 site rule, or that at least some states would eliminate the fixed-rate option for the calculation of avoided costs.”

But the court concluded that vacatur would cause severe trouble, as several states have already initiated proceedings in response to the order and some utilities already have received relief from mandatory purchase obligations with facilities rated at 5 to 20 MW.

“Victory. Again,” Chatterjee posted on X in response to the news. “The Chatterjee FERC record in the courts is quite strong.”

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Report Shows Rapidly Growing Need for EV Chargers in California

California will need to double its public EV charging infrastructure between 2030 and 2035 to serve the expected number of electric vehicles in the state, according to a new report by the California Energy Commission (CEC).

That draft Electric Vehicle Charging Infrastructure Assessment, which highlights the massive needs stemming from the state’s aggressive transportation decarbonization goals, coincided with the release of a CALSTART working paper on phasing the national EV charging infrastructure build-out.

The CEC assessment estimated that by 2035, more than 15 million light-duty electric vehicles in California would require more than two million chargers at public and “shared private” locations, more than doubling the seven million vehicles and one million chargers projected for 2030. This estimate did not include chargers installed in single-family homes but included shared private locations such as multifamily dwellings and workplaces.

The estimate of 15 million electric light-duty vehicles represents a tenfold increase from today. In the first quarter of 2023, California surpassed 1.5 million light duty electric vehicles, with nearly 85% full EVs, 15% plug-in hybrids (PHEVs) and less than 1% hydrogen fuel cell vehicles. In that quarter, full EVs and PHEVs accounted for more than 20% of new passenger vehicle sales. Light-duty vehicles were defined as vehicles with a gross vehicle weight rating below 10,000 pounds, primarily privately owned cars and trucks.

The assessment was the second biennial report required under Assembly Bill 2127. The draft report extended the 2021 analysis by five years to 2035, the target date for Gov. Gavin Newsom’s ambitious transportation electrification goals. His Executive Order N-79-20 set goals for 100% zero-emission new passenger car and truck sales and 100% zero-emission vehicle operations for drayage trucks by 2035.

For the grid, peak weekday charging for light-duty vehicles is likely to reach 4,000 MW in the middle of the day by 2030, with more than a third of that from DC fast chargers. Residential charging, in contrast, would peak overnight, with the estimated demand showing a significant rise at 9 p.m. when time of use rates drop.

The assessment’s estimates for the mix of Level 1, Level 2 and DC fast chargers for light-duty vehicles appeared to be conservative, with only 83,000 DC fast chargers in the 2.11 million total, or less than 4%. That is a much lower percentage than today when California has 9,808 DC fast chargers to its 82,000 public Level 2 chargers.

In addition to building out EV charging infrastructure for passenger vehicles, the assessment forecast demand for fast chargers for commercial vehicles. The 377,000 medium- and heavy-duty EVs in 2035 would need an additional 256,000 20 to 150-kW DC fast chargers in depots, as well as 8,500 higher powered 350 to 1,500-kW public DC fast chargers. For medium- and heavy-duty vehicles, the load on the grid is more spread, with a peak demand in 2030 of 800 MW overnight, largely from vehicles at depots.

CALSTART, a nonprofit consortium focused on clean transportation, released a working paper on charging infrastructure for zero-emission medium- and heavy-duty vehicles throughout the United States. In Phasing in U.S. Charging Infrastructure: An Assessment of Zero-Emission Commercial Vehicle Energy Needs and Deployment Scenarios, CALSTART recommended phasing the building-out of commercial vehicle charging infrastructure, starting with “favorable launch areas.” The phased approach could support commercial EV uptake at the rates specified in the Global Memorandum of Understanding on Zero-Emission Medium- and Heavy-Duty Vehicles (Global MOU), which the United States signed in 2022.

“This phased approach can manage distribution grid upgrade timelines and maximize utilization even with the Global MOU’s attainable market penetration rates, which exceed those proposed by U.S. regulators,” the report said. “Favorable regions include where 1) industry concentrates, 2) public and private funds have high leverage, 3) policy is supportive, 4) energy will cost less or 5) distributed grid modernization will occur.”

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Va. SCC Orders Dominion to Suspend Unapproved DER Interconnection Rules

The Virginia State Corporation Commission last week ruled that Dominion Energy overstepped its authority in requiring distributed solar for large customers to go through new processes that led to spikes in the cost of installation.

The Virginia Distributed Solar Alliance filed a complaint against the new procedures in June, alleging they overstepped the regulated utility’s authority, as the SCC has been looking into the issues around interconnection of distributed sources in other cases. The SCC last approved interconnection rules back in 2020 and it is now looking at additional changes.

The commission on Aug. 30 agreed to suspend the parameters and interconnection agreements until it wraps up its open proceedings looking into the issues, but it declined to “address the myriad of additional relief” sought by the solar group.

The group’s other requests can be taken up in other proceedings, the SCC said. It also noted that it was not taking lightly Dominion’s claims about safety and reliability, but that it lacked authority to implement the new processes without a prior order.

“Dominion should continue to take the actions necessary to maintain the immediate safety and reliability of its system; this may include, but need not be limited to, seeking specific authority from this commission in one or more formal proceedings,” the commission said.

The utility adopted new parameters for projects between 250 kW and 1 MW and projects that range from 1 to 3 MW in December 2022, but the solar group’s complaint focused on their impact on projects below 1 MW, which are midsized, nonresidential projects. The complaint alleged that the new rules have led to costs, delays and barriers to adding such distributed generation around Virginia.

The rules that were suspended by the SCC led to “unprecedented” costs and delays by potentially requiring distributed solar to pay for substation upgrades and dark fiber cable and relay panel equipment. Dark fiber costs between $150,000 and $200,000/mile; relay panels can cost $250,000 for equipment and potentially more than double that for engineering, mobilization and construction management.

The complaint listed a number of anecdotes, including one at the James River Juvenile Detention Center for Henrico County, where Dominion estimated $2.25 million in preliminary costs for a 686-kW system. Prince William County Schools faced similar costs on a 987-kW array it was planning. Both projects, and others owned by private firms, proved too expensive with the extra costs that Dominion assessed under the now-suspended rules.

Dominion had argued in a filing last month that it needs to update the rules as distributed generation has grown rapidly in Virginia since a law passed expanding its net energy metering program.

“As a result of these changes, more net metering generation, with higher capacity ratings, are now rapidly developing and penetrating the company’s electric power system,” the firm said. “The company has been tasked with integrating more net metering distributed energy resources, with higher capacity ratings, that are now permitted to produce up to 150% of the customer’s expected annual energy consumption.”

The parameters suspended by the SCC were meant to ensure Dominion’s ability to specify the equipment and technical specifications needed to establish safe and reliable interconnection, the company said.