Utility regulators in several states are taking the unusual step of telling electric companies to redo their long-term energy road maps, a move that could dramatically alter the trajectory of fossil fuels and renewables.
The action from Mississippi to Virginia is aimed at bringing more carbon-free sources online and could force utilities to close their remaining coal-fired power plants early and add more battery storage, wind and solar to their systems.
Removing fossil fuels and adding renewables also will inch states closer to meeting President Biden’s proposal to decarbonize the power sector by 2035.
For climate advocates, the shift is a breath of fresh air: State utility regulators are known for rubber-stamping an electric company’s integrated resource plan (IRP) or brokering deals that lead to small, inconsequential changes. Now many regulators are changing course so electric companies’ plans fall in line with state clean energy laws enacted in the past few years. The shift currently is apparent in three states, although others could follow, depending on when and how they handle IRPs, analysts say.
IRPs arguably are the most important part of what an electric company does outside of producing and distributing power. They are the blueprint to how much and what type of megawatts — whether fossil fuel or low carbon — the utility wants to add to the grid over the next 10 to 20 years.
More broadly, the plans are a window into whether the power company is hanging on to a century-old model of building gigantic power plants or is moving with industry trends that include distributed generation sources. What’s more, they tee up what’s next: a request to bill customers for those investments.
"Basically saying that you are going green is not controversial for the utilities," said Paul Patterson, a utility analyst with Glenrock Associates LLC. "I think the controversy for the utilities will be the regulatory treatment that they get and the cost that commissions are willing to go forward with."
The detailed blueprints also highlight the tug of war that utilities face by sticking with routine investments or overhauling their power grids to support new technologies and cleaner sources of electricity. The latter typically is costlier and requires changes in state policies.
"The industry is going through some pretty significant changes and some disruptive ones," Patterson said.
The speed of the change, however, clashes with the protracted nature of utilities looking out two decades or more and figuring out how much and what type of generation they need to keep electrons flowing on the power grid. It also takes between three and six months for regulators to vet and approve an IRP because of the time needed for others to weigh in via written testimony and hearings.
While it’s clear that traditional renewable fuels such as solar and wind continue to get cheaper and more plentiful, the industry is banking on storage to do so as well. Then there are unknowns such as the future of carbon capture for natural gas, next-generation nuclear reactors that are likely to be smaller and the emergence of hydrogen. Even with those unknowns, many utilities are including those technologies in their IRPs.
"It wouldn’t surprise me that that might not cause some hesitancy on state regulatory or policymakers to approve long-term plans that might lock them into a path that might not make that much sense," Patterson said.
It’s likely that state utility regulators and their staffs will take a more critical look at IRPs under the Biden administration, as the federal government and states rush to carry out a monumental clean energy transition to combat climate change.
"What we’re seeing is a debate: How much renewables can we do without impacting reliability and really retiring some gas or coal plants to keep costs down, too?" said Charles Fishman, an equity analyst with Morningstar Research Services LLC. "With the cost of renewables coming down, the cost of battery technology coming down, they are taking a fresh look at this."
One of the states where the pushback on utilities is playing out is Virginia. The state’s utility regulators determined this month that Dominion Energy Inc.’s road map did not adequately take into account the state’s landmark climate law, the Virginia Clean Economy Act of 2020.
The law, which Gov. Ralph Northam (D) signed last April, requires Virginia to achieve net-zero emissions by 2050. The measure took effect last summer and mandates that Dominion and Appalachian Power, the state’s other large investor-owned utility, begin to retire their carbon-emitting electric generation facilities.
The State Corporation Commission concluded that Dominion’s IRP was not "reasonable" or "in the public interest," and required the monopoly utility to make a series of changes when it files required updates this year and in 2022.
Both Dominion and Appalachian Power are required by law to file a detailed road map every three years outlining how the utilities will meet electric demand over the next decade.
This is the second time in the past three years that the SCC has initially rejected Dominion’s road map. In 2018, the commission rejected the blueprint outright, requiring Dominion to submit a new plan in 2019 (Energywire, Dec. 11, 2018).
This time, instead of rejecting the entirety of Dominion’s 2020 plan, the commission is requiring the utility to issue a revised compliance plan with the law when it submits its 2023 IRP, as well as provide 2021-2022 updates.
Jeremy Slayton, a Dominion spokesperson, said the utility plans to review the commission’s recent decision and incorporate its direction in subsequent IRP filings.
"We appreciate the Commission’s acknowledgement of the vital role electric reliability plays and look forward to working with our regulator to make our strong record of reliability even better," Slayton said in an email.
Among other changes, regulators asked Dominion to include in its updated plan a "least-cost" analysis. The current road map does not offer the least expensive way to achieve the state’s carbon emissions goals or renewable targets, they said.
The Virginia commission directed Dominion to include energy efficiency as a core part of the state’s long-term energy and climate action plans. The utility’s blueprint did not include modeling for energy efficiency targets after 2025.
The commission also pressed Dominion to provide more details on its environmental justice plans. The regulators said the utility, for example, could consider the impacts of unit retirement decisions on front-line communities.
Virginia’s environmental justice policy is broad and includes "the fair treatment and meaningful involvement of every person, regardless of race, color, national origin, income, faith, or disability, regarding the development, implementation, or enforcement of any environmental law, regulation, or policy," the commissioners wrote in the order.
Will Cleveland, a senior attorney at the Southern Environmental Law Center who intervened in the case, said he counts the commission’s rejection of Dominion’s plan as an important step for achieving Virginia’s renewable goals affordably. He said a monopoly utility like Dominion faces no competition, necessitating "watchdog" regulators.
"There is a least-cost version of the Clean Economy Act the utilities can pursue that will provide them with ample growth opportunities without overcharging customers," he said. "It’s up to the regulators to ensure that happens, because the utility will not do it on its own."
In South Carolina, regulators sent Dominion back to the drawing board after its IRP did not include renewables and storage before 2026 and did not entertain closing coal-fired power plants before 2028. Broadly, the proposal failed to meet the standards of a 2019 law known as the Energy Freedom Act, which requires all-source procurement for major power producers.
Prior to this law, the state Public Service Commission virtually had no say in utility resource planning. Now an IRP must meet a standard that it is "the most reasonable and prudent" plan for the company and its customers. The heart of this new process is to ensure that all resource options get a fair shot, said Kate Lee Mixson, an attorney with the Southern Environmental Law Center.
"I think that was definitely the source of the major change in South Carolina, and the commission really seemed to latch on to this … standard," Mixson said.
The decision was pivotal for the state’s regulators, but it stems from a long and winding backstory that starts with a failed nuclear power plant. What was known as South Carolina Electric & Gas Co. was a partner in building two reactors at V.C. Summer when skyrocketing costs pushed the main contractor into bankruptcy.
The PSC has reviewed the status of V.C. Summer multiple times over its construction life and approved multiple rate increases to support it, yet the bankruptcy seemed to catch everyone by surprise.
The electric companies decided it was cheaper to walk away, setting off a political and legal firestorm that led to a complete overhaul of the PSC (Energywire, Sept. 24, 2020). That opened the door for a competitive bidding process for energy.
"I think this new PSC is taking an aggressive leadership role in part because of the history of the failed nuclear project and years of frustration in South Carolina of how energy was being generated and managed," said Will Harlan, a senior representative for the Sierra Club’s Beyond Coal campaign.
For Dominion’s part, the utility said in its IRP it did not need to add any generation during this upcoming planning period. Yet regulators in a final written order said the IRP must follow the law and "fairly evaluate the range of demand-side, supply-side, storage and other technologies and services available to meet the utility’s service obligations."
Adding more solar or storage as early as 2023 could lower utility bills even if Dominion doesn’t need the capacity on its system, regulators said.
Dominion must emphasize renewables and energy efficiency in its rewrite, they said. The utility also must boost energy efficiency by studying how to reach 1% to 2% savings.
In lengthy hearings last fall, the Public Service Commission pressed Dominion on why it was not shutting down its coal fleet earlier and adding more renewables, especially in light of the company’s net-zero carbon goal as well of that of Virginia’s.
"You don’t want to wait 20 years to start a plan to reduce carbon emissions; that’s too late in the game," said Commissioner Tom Ervin, who asked whether Dominion had considered using carbon capture technologies and raised the issue of carbon’s effects on public health.
James Neely, a Dominion engineer, pointed out that Dominion’s zero-carbon goal is 30 years away and that it has put pollution control equipment on its coal plants.
"We can wait 30 years and still meet the net-zero goal, that’s not a problem," Neely said. "You can retire plants very quickly, and we can build solar plants very quickly."
Commissioner Headen Thomas called Dominion’s net-zero goal "not very sincere."
"It’s just kind of starting to sound like that’s a really nice thing to have out there for public relations … whereas nobody at the company has to do anything," he said, asking what Dominion can do now.
Neely touted the company’s 40% carbon reduction from 2005 levels and said the goal is to reach 60% by the next decade. He raised an industrywide concern that technology is not available to hit a net-zero target and noted there’s a lot of work that still needs to be done.
Separately, regulators have asked Dominion to analyze the future of its remaining coal fleet. The North Carolina Utilities Commission has asked Duke Energy Corp. to do the same and include those results in its upcoming resource plans.
"Perhaps we’re now in an era where green washing or PR doesn’t carry that kind of weight," said Natalie Olson, campaigns director with Conservation Voters of South Carolina.
The commission’s decision is just one piece of South Carolina’s transforming energy industry. Issues such as market reform, helping communities economically when coal plants are being shut down, and allowing homeowners and businesses to generate their own electricity are coming into play.
"We need to keep working on our state laws and regulation," Olson said, noting that takes precedence over what’s happening at the federal level. "I’m hopeful, but there’s still so much work that needs to be done on the South Carolina side."
In other cases, regulators are cracking down on utility plans not because of enacted low-carbon laws, but because of large reserve margins — a factor exacerbated by aging fossil fuel plants.
Southern Co.’s Mississippi Power will file its first formal long-term energy plan in April under a new process created by state utility regulators (Energywire, June 17, 2019). Many argue that the action, the first time regulators in the state have called for a formal energy planning process for electric companies, could significantly boost renewable power.
As part of that new process, the Mississippi Public Service Commission took a surprising move this year in requiring Mississippi Power to remove roughly 1 gigawatt of excess electricity from its system, pointing to its coal and gas plants. The move mandates that the utility not include that 1 GW in its upcoming IRP on April 15.
It is typical for electric utilities to include information in their IRPs about how much generation capacity they have in reserves in case of an emergency. The so-called reserve margin is usually between 15% and 20%, although some electric companies have argued to have excess reserves higher than that to meet reliability needs in the winter, otherwise known as the "winter peak" (Energywire, Sept. 9, 2019).
But the power sector has faced flat demand for years, largely due to more efficient appliances. That, combined with the expense of retrofitting aging power plants to comply with environmental regulations, usually makes an economic case to shut them down.
Typically, it’s the electric company making a shutdown proposal to utility regulators in an IRP, however, not the other way around. The challenge comes with how to handle the unrecovered investment if the power plant is shuttered ahead of its original life span. Those costs typically fall on the backs of customers and can be expensive.
"We are complying with the PSC’s Order to make a filing on April 15 to address the 950 MW. At this time, we are reviewing the analytics and research to make a decision that is in the best interest of our customers," Mississippi Power spokesperson Jeff Shepard said in an emailed statement to E&E News.
The PSC’s directive stems from a September 2020 review of Mississippi Power’s reserve margin plan as well as the company’s own analysis that was done outside of the IRP process. It shows excess capacity in upward of 40% through 2028, according to PSC documents. The company would exceed its summer capacity by 1 GW from 2021 through 2023.
"This commission finds that some measure of capacity reduction would likely be in the best long-term interest of customers," a December 2020 order from the commission states. No party "appears to disagree" with the statement.
The September 2020 review highlighted a total of six aging coal and natural gas units, or 1,500 MW. Four of those units are in Mississippi at Plants Daniel and Watson, and the remaining two are shared with Alabama Power at Plant Greene County.
Mississippi Power and Bates White "agree that accelerating the retirement of some combination of [those power plants] represents the most attractive option for reducing Mississippi Power’s excess reserve margin," regulators wrote.
The days of at least one unit at Plant Daniel are numbered already. NextEra Energy Inc.’s Gulf Power Co. has called for the unit it owns to be shut down by January 2024 (Energywire, Oct. 24, 2019).