This story was originally published by Virginia Mercury.

Power producers in the northeastern and Mid-Atlantic carbon market known as the Regional Greenhouse Gas Initiative paid a record price for carbon allowances in the first auction of 2022, which netted Virginia $74.2 million for flood protection and low-income energy efficiency programs. 

The clearing price for allowances, which producers must buy for each ton of carbon dioxide they emit, rose to $13.50, exceeding the $13 record set in the December 2021 auction. 

Under current state law, $33 million of that money must go to the Community Flood Preparedness Fund, which supports local flood protection efforts, while just over $37 million must go toward low-income energy efficiency programs run by the Department of Housing and Community Development. 

But while the proceeds signal another year of RGGI revenues that far exceed initial projections by state budget officials, Virginia’s future in the market remains uncertain. 

Republican Gov. Glenn Youngkin remains committed to withdrawing the state from RGGI, which he has said has not reduced emissions while imposing unnecessary costs on Virginia electric utility ratepayers. 

Youngkin and Republicans in the General Assembly are trying a variety of strategies to remove Virginia from the regional carbon market, from budget language to legislation to an executive order. 

Legislation to pull Virginia out stalled this session after Democrats in the Senate blocked proposals to repeal the 2020 act authorizing RGGI participation. And while the budget proposed by the Republican-controlled House of Delegates does not include language recommended by Youngkin explicitly repealing the act, it would prohibit three state agencies from spending $371.2 million in expected RGGI funding over the next two years. 

Earlier this month, 26 environmental and energy groups urged budget negotiators to reject RGGI provisions, arguing that “these sorts of major policy changes cannot be fully evaluated and studied in the budget process.” 

The General Assembly adjourned over the weekend without agreeing on a budget, setting up a special session that had yet to be scheduled. 

Whether Youngkin can withdraw Virginia from RGGI without legislative action remains disputed. Nevertheless, the governor’s Executive Order 9 ordered the Virginia Department of Environmental Quality to issue a report on the costs and benefits of RGGI participation as well as an emergency regulation rolling back existing rules on the books. 

The report and proposed regulation were due Feb. 14 but have not been made publicly available. A spokesperson for Youngkin did not provide a copy of either in response to multiple requests.

LS Power relief rejected again 

Democratic lawmakers this session also rejected proposals to offset some of the RGGI compliance costs being borne by LS Power, a large generation, distribution and transmission company that operates a power station in Doswell. 

While Virginia’s electricity markets are regulated, just over a quarter of the emissions that Virginia producers are required to purchase allowances for come from merchant generators, or unregulated power producers that sell power to the broader regional grid. 

Public data on annual emissions from the RGGI CO2 Allowance Tracking System shows eight facilities in Virginia that are not operated by the regulated utilities and must buy allowances at auction. 

Of those, LS Power’s Doswell plant produces the most emissions, followed by the Potomac Energy Center in Loudoun, the Tenaska plant in Scottsville and a cogeneration facility in Hopewell. 

Since 2020, LS Power has been asking the General Assembly for a special carveout in the RGGI law that would let it purchase carbon allowances at a discounted rate. 

The company has argued that it needs relief from the more than $50 million in costs it will incur through 2025 as a result of being required to buy carbon allowances through RGGI auctions. Long-term contracts to sell power from the Doswell plant signed in 2016 and 2017 prevent LS Power from passing on its allowance costs to buyers. 

While several other states that participate in RGGI have offered protections for companies locked into long-term power contracts at the time the state joined the market, Virginia has chosen not to do so. 

“This has left Doswell saddled with the prospect of absorbing certain compliance costs that, as far as we know, no other 25-megawatt or larger electricity generation company in Virginia must absorb,” LS Power Managing Director Matthew Mitchell wrote in a February letter to the Senate Finance and Appropriations Committee. 

All plants with a capacity of 25 megawatts or more must purchase carbon allowances under RGGI. 

Democrats rejected LS Power’s request in 2020 on the grounds that it would result in revenue losses for the state that would otherwise be channeled to flood protection and low-income energy efficiency programs. 

This year the company tried again, later amending its plea to cut down the amount of costs the General Assembly would allow it to avoid from approximately $50 million to $30 million. 

Nevertheless, Senate Democrats again killed the legislation. 

“I’m not without sympathy for LS. That being said, two years ago, in this very room, we hashed this out ad nauseum,” said Sen. Lynwood Lewis, D-Accomack, during one committee hearing. “LS is a large sophisticated company with lots of smart people and resources available to it. And they made a bad business decision in an environment where this train was coming down the track. Other people made smarter decisions.” 

Virginia Mercury is part of States Newsroom, a network of news outlets supported by grants and a coalition of donors as a 501c(3) public charity. Virginia Mercury maintains editorial independence. Contact Editor Robert Zullo for questions: info@virginiamercury.com. Follow Virginia Mercury on Facebook and Twitter.

As Virginia nets another $74 million, RGGI uncertainty lingers is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

In Dominion Energy’s quest to get regulators to approve the large-scale rollout of smart meters to Virginia customers, the fourth time was the charm. 

Friday, after three earlier rejections, the Virginia State Corporation Commission signed off on a proposal by the electric utility to replace roughly 1.1 million existing meters with newer technology that can allow customers to adjust their energy usage based on real-time data. 

The project, which was included in the utility’s latest Grid Transformation Plan, will cost $198.3 million and bring Dominion close to a full deployment of smart meters in Virginia by 2023. Replacement of the final 250,000 to 300,000 existing non-smart meters will be proposed as part of the company’s next plan, which would lead to full deployment by 2024. 

Augustus Johnson, Dominion’s director of electric distribution grid solutions, called smart meters — formally known as advanced metering infrastructure — a “fundamental building block” of the utility’s grid transformation efforts. 

With them, “we’ll be able to offer all of our customers faster storm service connections, greater information and options to manage their usage and bill and streamline the integration of distributed energy resources like solar panels and battery storage at their homes,” he said. 

Dominion has been vying for SCC approval of its plans to deploy smart meters across its entire Virginia territory since the General Assembly approved the Grid Transformation and Security Act in 2018. 

The utility has contended that as it modernizes the electric grid, smart meters will provide the data needed to integrate an increasing number of distributed energy resources like rooftop solar panels and electric vehicles. In addition to letting the utility track customers’ energy use electronically, smart meters can provide information to customers themselves, allowing them to adjust their usage and potentially take advantage of innovative electric rates designed to drive down use at times of peak demand. 

Dominion has been steadily replacing its older meters, known as automated meter reading or AMR devices, since 2008. As of the end of November, it had deployed 1.2 million within the Virginia system, with recent efforts focusing on Petersburg, parts of Southside and Hampton Roads, and the eastern portion of Richmond. 

But regulators have been reluctant to sign off on the costs of a coordinated system-wide deployment. 

The SCC twice denied smart meter proposals in Dominion’s Grid Transformation plans and in April 2020 again rejected the utility’s request to reconsider its latest denial. In a formal order, the commissioners said they believed the potential benefits of Dominion’s proposed smart meter rollout were “too speculative and uncertain for the commission to choose to approve such a large expenditure at this time, the large costs of which impact Dominion’s customers.” 

In the most recent plan approved by the SCC Friday, environmental and consumer protection nonprofit Appalachian Voices had argued that regulators should condition their approval of the smart meter rollout on the utility taking several other steps, such as offering customers a rebate for reducing electricity usage on days when demand has hit a critical peak. 

The commission turned down that suggestion, however and approved the rollout plan as a whole, pointing to other steps Dominion has taken to justify a broader deployment. 

In particular, the SCC cited the utility’s new time-of-use rate, a type of electric rate designed to incentivize customers to decrease their electricity usage at times of peak demand and shift energy-intensive activities like vehicle charging to off-peak times. Not only does Dominion now offer an experimental TOU rate, said the commission, but it has “provided a timeline for system-wide implementation” of such rates. 

The commission had previously criticized the utility for not incorporating time-of-use rates into its smart meter plans, saying that Dominion had “failed to submit a comprehensive proposal” to roll them out across its territory even while asking customers to pick up the costs of smart meters. 

Other reasons proffered by the SCC in support of their approval this Friday included declining vendor support for existing meters, as well as that technology’s “functional limitations.”  

Virginia Mercury is part of States Newsroom, a network of news outlets supported by grants and a coalition of donors as a 501c(3) public charity. Virginia Mercury maintains editorial independence. Contact Editor Robert Zullo for questions: info@virginiamercury.com. Follow Virginia Mercury on Facebook and Twitter.

Dominion finally gets approval for large-scale smart meter rollout is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

PORTSMOUTH —  Siemens Gamesa announced Monday that it plans to build the United States’ first offshore wind turbine blade facility at the Portsmouth Marine Terminal, notching a major win for Virginia as it strives to become a hub for the nation’s fledgling offshore wind energy industry. 

The announcement was made Monday at the terminal by U.S. Energy Secretary Jennifer Granholm and Virginia Gov. Ralph Northam. 

The Spanish-German wind engineering company said it plans to invest more than $200 million in the Portsmouth Marine Terminal facility, which will produce blades for offshore wind projects throughout North America, per Northam’s office.

The facility is expected to create over 300 jobs. 

Virginia’s largest electric utility, Dominion Energy, previously selected Siemens Gamesa as the turbine supplier for its 2.6 gigawatt Virginia Coastal Offshore Wind project being developed 27 miles off the coast of Virginia Beach. A 12 megawatt pilot constructed by Dominion became the nation’s first offshore wind installation in federal waters and began delivering energy to customers in January 2021. 

Offshore wind is increasingly becoming a critical component of both electric power producers’ plans to transition away from fossil fuels and state and federal aspirations to develop renewable energy that can replace coal and natural gas while driving economic growth.

Earlier this month, President Joseph Biden’s administration laid out an ambitious plan to develop offshore wind along much of the East Coast, West Coast and Gulf of Mexico. In March, the administration set a target of deploying 30 gigawatts of offshore wind by 2030. 

Virginia has also set an aggressive goal under the 2020 Virginia Clean Economy Act of developing 5.2 gigawatts of offshore wind by 2034. Dominion’s CVOW project, which would produce half of that power, is currently being reviewed by the U.S. Bureau of Ocean and Energy Management. 

But even as states race to develop wind projects, turbine components continue to be produced overseas, with major manufacturers including Siemens Gamesa telling Reuters earlier this year that they need to see a reliable pipeline of projects moving forward in the U.S. before putting down roots stateside. 

Shipping turbine components across the Atlantic for U.S. projects, however, comes with special challenges. 

Under the federal Jones Act, any vessel carrying goods between two points in the U.S. must be built and registered in the United States. Despite that restriction, no such vessels with the capacity to transport turbine components currently exist in the U.S. Dominion is building the first Jones Act-compliant offshore wind installation ship in Texas, which has been christened Charybdis after a sea monster in “The Odyssey” and is expected to be completed by late 2023.

Virginia Mercury is part of States Newsroom, a network of news bureaus supported by grants and a coalition of donors as a 501c(3) public charity. Virginia Mercury maintains editorial independence. Contact Editor Robert Zullo for questions: info@virginiamercury.com. Follow Virginia Mercury on Facebook and Twitter.

Siemens Gamesa chooses Virginia for offshore wind turbine blade factory is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

When Dominion Energy broke ground in 2008 on the largely coal-fired Virginia City Hybrid Energy Center, then-Lt. Gov. Bill Bolling called it “the largest economic development project in the history of Southwest Virginia.” 

Today, the facility, the last coal plant to be built in Virginia, remains a local economic force, tipping more than $8.9 million in property taxes into Wise County’s coffers in 2020. But that investment comes at a price. According to Dominion’s own calculations, the continued operation of Virginia City is expected to cost utility ratepayers — none of whom live in Wise County — $472 million through 2029. 

Those numbers have become key touchstones in a struggle over how fast Virginia should wind down its coal fleet, with the utilities pushing to keep their remaining large investments in service through 2040 or 2045 and many environmental and consumer groups arguing that closures should happen far sooner, preferably by the end of the decade. 

“From a utility’s perspective I think the question to be asked is, ‘Do the benefits of continuing to operate this facility outweigh the costs to the customers?’” said Will Cleveland, an attorney with the Southern Environmental Law Center. 

Both sides have emphasized different costs and different benefits. Advocates for faster closure highlight the declining use of coal plants to provide customers with energy, the additional costs ratepayers will have to shoulder to keep them running and the need to stop emitting carbon. Utilities meanwhile point to their power reserve obligations, local economic impacts and the cost of rapidly rolling out renewables to replace shuttered coal generators. 

Keeping Virginia City afloat, said Dominion spokesperson Rayhan Daudani, “helps us provide reliable power for our customers and also plays an important role in Southwestern Virginia with hundreds of jobs and significant local revenue while helping clean up millions of tons of waste coal and thereby improving regional water quality.” 

Cleveland, however, described Virginia City as “a power plant in search of a reason to exist.” 

“I think you can both close the coal plant and provide the necessary assistance to Wise County all for less money than it now costs Dominion customers to keep the thing open,” he said. 

The last coal plants

Once the driving force behind Virginia-produced electricity, coal has over the past decade found itself steadily losing its corner of the market. 

Part of the reason is purely economic: The shale revolution ushered in a glut of cheap natural gas that has been able to undercut coal as electric utilities’ fuel of choice. Capacity factors — an indicator of how often plants are run, with a factor of 100 percent indicating constant usage at maximum output — show declining usage of coal plants in favor of natural gas. Between 2017 and 2019, Virginia City’s capacity factor fell from about 62 percent to 22 percent, while that of the Clover Power Station in Halifax County dropped from about 43 percent to 17 percent.

Clover “used to provide about 25 percent of our power, and last year it was about 5 percent of our power,” said Kirk Johnson, ODEC’s senior vice president for member services. 

Appalachian Power’s use of its Amos and Mountaineer plants, which are located in West Virginia but serve the company’s Virginia customers, have also fallen. According to utility data, capacity factors dropped between 2017 and 2020 from an average of 54 percent to 40 percent for Amos and from 62 percent to 46 percent for Mountaineer, with a spike in use at the latter in 2019. 

Natural gas isn’t the only force exerting pressure on coal, however. Heightened environmental regulation has also played a role. Rules introduced by the U.S. Environmental Protection Agency in 2015 to govern coal ash and coal wastewater disposal are forcing plants to either make costly upgrades or shutter; last Monday, the agency announced it plans to begin strengthening them further. And rising concern about climate change-causing carbon emissions has led a growing number of states to pass laws to phase out fossil fuels. Coal plants, which are generally older and produce more carbon dioxide than their natural gas counterparts, tend to be first on the chopping block. 

Virginia is no exception. The 2020 Virginia Clean Economy Act set a 2024 deadline for the closure of most of the state’s coal units, although it allowed Virginia City and the Clover Power Station jointly owned by Dominion and Old Dominion Electric Cooperative to stay open until 2045. 

“The economics are already showing that it doesn’t make any sense” to keep operating most coal plants, said Dori Jaffe, a senior attorney with the Sierra Club who is involved with current litigation before Virginia’s State Corporation Commission concerning two coal plants owned by Appalachian Power Company. 

Operators have in numerous cases agreed. Dominion has retired or converted 11 coal units in Virginia over the past three years and plans to close its last two coal units at the Chesterfield Power Station in 2023. Appalachian Power closed its last three Virginia coal units in 2015. Non-utility companies shuttered the Spruance coal plant near Richmond this January and announced plans to convert a King George coal plant to storage and solar in March. 

Nevertheless, a few large coal plants continue to operate for the foreseeable future. Virginia City is one. Clover may be another. Although Dominion has projected a 2025 retirement date for the plant in long-range planning, no firm commitments have been made, and the facility’s shared ownership means both Dominion and ODEC must agree to any closure plan. 

Appalachian Power’s Amos and Mountaineer coal plants present a curious problem due to their West Virginia location. While not subject to Virginia closure deadlines, both facilities face significant pressure from state law requiring utilities to source an increasing amount of their electricity from renewables through 2050. 

“The costs incurred to comply with the Virginia Clean Economy Act may be higher because of continued operation of Amos and Mountaineer than it otherwise would be,” said Cleveland.

When Appalachian Power intends to shutter those plants remains a question mark. During its 2020 rate review, the utility asked regulators to plan for accelerated retirement dates of 2032 and 2033 for the facilities rather than 2040, although the later date has resurfaced this spring in a fresh round of proceedings over environmental investments. 

The utilities acknowledge the declining use of coal plants but say that isn’t the whole picture. Serving daily load is just one of their obligations, they point out. Maintaining power reserves sufficient to meet year-round demand spikes is another, one that can’t be ignored. 

“We are required to have a certain level of capacity — in other words, we must be ready to provide our customers a certain amount of power at any given time,” said Appalachian Power spokesperson Jeri Matheney. Amos and Mountaineer represent nearly two-thirds of the company’s capacity, she said; retiring them early “would expose the company and our customers to an imprudent level of uncertainty and market volatility.” 

Johnson, the ODEC executive, also said that even though Clover is “not much of an energy source” for the cooperative, it is “a valuable capacity resource so we can meet our capacity obligations” within the regional electricity market. 

“We spend a lot of time talking about the future of Clover and what is in the best interest of our members,” he said. 

To invest or not invest

Dominion and ODEC remain in the driver’s seat when it comes to decision-making about Virginia City and Clover. But Appalachian Power’s hand is being forced this spring as it seeks state approval for several large investments to comply with tighter federal coal ash and coal wastewater disposal regulations at Amos and Mountaineer. 

The choices are stark. If Appalachian doesn’t comply with the coal ash rule, it will have to close both facilities by 2023 at the latest; not complying with the wastewater rule would trigger a closure date of 2028. 

The utility has asked regulators for permission to do both, allowing the plants to operate through 2040. The price tag for Virginia and West Virginia customers would be $250 million, split evenly between the two projects. As a result the average Virginia customer would see a monthly bill increase of $2.50. 

Appalachian has said continuing to operate the plants through 2040 is “the most economical solution for customers,” and that if it was forced to retire one or both by 2028, it would have to spend billions of dollars on replacements “much earlier than necessary.” 

“Virginia customers would bear the costs of this unprecedented capacity overhaul,” said Matheney. 

But while the company has faced no opposition to its coal ash investments, which are widely viewed as cleanup costs, both the Sierra Club and the Virginia Office of the Attorney General have disputed the wisdom of the wastewater investments that aim to prolong Amos and Mountaineer’s lives through 2040. 

“This is a moment when neither market nor regulatory trends favor coal generation. And yet the company is requesting recovery from ratepayers of additional capital that it wants to invest into West Virginia coal plants in the apparent hope that the plants will weather the economic and regulatory headwinds that are faced by other coal plants all over world,” said Sierra Club attorney Evan Johns during proceedings before the State Corporation Commission this June. 

SCC staff too expressed hesitancy about the prospect of racking up further costs.

“It would appear to be inconsistent with market and industry trends to assume that the Amos and Mountaineer plants will be able to operate economically in the market through 2040,” said utilities policy specialist Earnest White in May testimony on the proposal.  

A hearing examiner sided with the skeptics earlier this month, saying she was “concerned about the validity of APCo’s conclusion that the [wastewater] investments will ultimately be beneficial to ratepayers” and recommending that the commission withhold approval of them until the utility could provide more detailed analysis. 

Kentucky regulators on July 15 took a similar stance, denying Appalachian’s proposal to make the same upgrades at its Mitchell plant on the grounds that it hadn’t proved the projects were “a reasonable, cost-effective alternative.” West Virginia regulators are still mulling the same proposal before the Virginia commission. 

A replacement for coal 

No accounting of coal’s costs can be complete, say both the utilities and advocates of early closure, without an accounting of what it will cost to replace it. 

“No party disputes that the company will have to acquire replacement capacity for the plants at some point in the future,” Appalachian Power wrote in a filing with the State Corporation Commission last week. 

When that point in the future should be is hotly disputed. 

Early closure advocates say that phasing out the plants sooner would be better not only for curbing air pollution but in some cases on economic grounds. 

Continuing to operate coal plants would be a matter of “throwing good money after bad,” said Cleveland of the Southern Environmental Law Center, pointing in particular to Virginia City’s projected 10-year losses of $472 million. (Appalachian Power doesn’t make similar valuations of its facilities publicly available.) The plants have been built, so “customers are on the hook for that regardless of whether it retires now or in 30 years.” 

But, he asked, “Is it beneficial to the customer to ask them to incur yet more cost to keep operating?” 

Appalachian Power has argued that pushing off replacement costs to the future while the coal plants finish out their lives would be better for customers. One Sierra Club proposal to procure 6.3 gigawatts of solar and storage as a replacement by 2028 at an estimated cost of $5 to $7 billion was described as “simply too much, too fast to be feasible” by James Martin, the director of resource planning strategy for Appalachian Power parent company AEP. 

“The only practical solution, and the most economic solution, is to preserve the dependable capacity that these units provide for our customers,” he testified to Virginia regulators. 

Much of the decision-making regulators will face in the Appalachian case, as well as any future case involving coal plant investments, comes down to whose accounting they accept. In the present proceedings, Appalachian contends early retirement of both plants would cost customers $1.5 billion by 2039, while the Sierra Club argues such a step would save ratepayers $670 million. 

Electric cooperatives like Old Dominion also face a separate set of challenges because of their non-profit structure, which gives them less flexibility in deciding how to handle early retirement costs. 

“We don’t have some tools like securitization that are available to investor-owned utilities,” said Johnson. “We can’t shove any of these costs or this depreciation on shareholders. It all has to come from those 1.5 million people that we serve at the end of the line.” 

Less abstract are the impacts the inevitable closures will have on plant employees. Appalachian spokesperson Matheney described the company’s facilities as “the primary employers and tax paying entities in many communities.”

“Our intent is to provide as much notice as is feasible, often as long as five years, to prepare for a closure,” she said. 

Other coal plants serve a similar function. 

“Our county has become very dependent upon the revenue from” Virginia City, Wise County resident David Rouse told a Senate subcommittee this winter. “It now provides about 20 percent of the county’s budget in terms of taxation. Not only would we suffer from the loss of employment but our schools would suffer significantly from the loss of revenue as would other county services.” 

Dominion has emphasized this financial contribution in regulatory testimony. Virginia City, it said during litigation over its 2020 long-range plan, “is expected to remain in the company’s fleet for reasons beyond the results of the economic analysis.” 

“In addition to serving customers’ energy and capacity needs, [Virginia City] support jobs, economic development and water quality improvements in the coalfield regions of the commonwealth, and reduces reliance on imported power,” the company wrote. 

Cleveland, who has consistently argued against the reasonableness of continuing to operate the plant, said that any early closure would need to be accompanied by “a very thoughtful companion effort to make sure that Wise County and its residents are not left out in the cold.” But, he added, “I think there are lots of ways to solve that problem.” 

Virginia Mercury is part of States Newsroom, a network of news outlets supported by grants and a coalition of donors as a 501c(3) public charity. Virginia Mercury maintains editorial independence. Contact Editor Robert Zullo for questions: info@virginiamercury.com. Follow Virginia Mercury on Facebook and Twitter.

Coal fuels less and less Virginia electricity. But when should utilities pull the plug on plants? is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.