Even with the Biden administration’s call for the power sector to decarbonize, many Southeastern utilities plan to add large amounts of natural gas to their grids, a move they say is necessary to support renewable projects in the queue.
The plans illustrate the challenge facing some U.S. regions as they aim to decarbonize: How can utilities move away from fossil fuels when they say natural gas is needed to back up renewables? Can gas lower emissions in the long run? Is it true that policies such as cancellation of the Keystone XL pipeline have raised gas prices? Will a reduction in gas lead to less grid reliability?
Take the case of Atlanta-based Southern Co., which recently announced plans to shutter roughly half of its coal fleet, following guidelines from federal wastewater regulations for power plants (Energywire, Nov. 5).
Alabama’s electricity powerhouse this fall told the state Public Service Commission it wanted to buy a 750-megawatt natural gas plant in Calhoun County, arguing that the generation is necessary to replace some of the coal that will be removed from the grid at the end of 2023.
Absent that, what’s known as Barry Unit 5 will have to keep running to ensure system reliability, the company said in an Oct. 28 filing. Running that inefficient coal unit is more costly, not to mention produces higher emissions, the document said.
“Alabama Power has a capacity need in the very near term, especially in 2023,” John Kelley, the company’s forecasting and resource planning director, said in written testimony to the PSC. “Calhoun can help meet this need if the resource is acquired by the target date in late 2022.”
Environmental advocates are skeptical, however, that the electric company needs the replacement megawatts at all.
If it does, “then Alabama Power should not be looking to replace it with another fossil fuel,” said Christina Andreen Tidwell, a senior attorney with the Southern Environmental Law Center.
“Alabama Power seems to be doubling down on gas at a time where utilities should be pursuing lower-cost and less-risky renewable energy and energy efficiency options,” said Tidwell. SELC is representing Energy Alabama and the Greater Birmingham Alliance to Stop Pollution, or GASP,in this case.
Similarly, with the Tennessee Valley Authority,critics frequently call out the federal agency for not cutting carbon emissions more aggressively, especially as President Biden has made fighting climate change a central part of his administration.
The utility’s desire to replace shuttered coal plants in Kentucky and Tennessee with natural gas has drawn the ire of environmentalists who say TVA is not in sync with Biden’s signature clean energy goals. Biden has called for decarbonizing the power sector by 2035.
TVA will continue to evaluate the best options to replace that generation in a process that will finish next year, said TVA President and CEO Jeff Lyash in an interview with E&E News. The choices include building out the transmission system, adding a combination of solar and storage, and building simple-cycle and combined-cycle natural gas.
A solution may be a combination of all or some of those possibilities — with the caveat that the generation includes dispatchable capacity to support the region’s heavy industrial users. That specific need rules out completely replacing the fossil fuel megawatts with solar and storage.
“That doesn’t provide the reliability, resiliency and the power quality that we need,” he said.
Lyash argues that natural gas allows the utility to eventually close its entire coal fleet and integrate 10,000 MW of solar.
“Without something as flexible in terms of capacity and voltage support and ramp rates,” that wouldn’t be able to happen, he said.
The Duke example
With Duke Energy, utility regulators in North Carolina took the unusual step of placing some of the company’s long-term plans in somewhat of a holding pattern starting this fall, acknowledging a new state law that would cut the state’s power-sector carbon emissions 70 percent by 2030, on a path to becoming net zero by 2050.
The law also requires Duke to submit a proposal for how it will cut carbon dioxide emissions from its fleet by the end of 2022. The North Carolina Utilities Commission last month asked the energy giant to file that plan by April 1.
Duke Energy filed its integrated resource plan in 2020 for its electric companies that encompass a wide swath of North and South Carolina. The IRP contained six paths the utility could take with its electricity mix, one of which included replacing much of its coal-fired generation with natural gas. Another called for adding an unprecedented amount of battery storage and renewables.
In South Carolina, regulators rejected Duke’s original plans, arguing that they did not meet a state law designed to boost clean energy. What’s more, regulators asked the electric company to use different natural gas pricing forecasts and change how it models solar and battery storage.
In North Carolina, the utility commission approved Duke’s short-term plans, which include shutting down one coal plant and not adding any natural gas over the next five years. Duke has no plans to add significant amounts of generation until after 2025, and regulators essentially delayed any further decision on Duke’s long-term plans until the company files the state-mandated carbon reduction proposal next spring. Duke will file another IRP in 2023.
“The commission has determined that it would be appropriate to provide additional guidance with respect to the preparation and submission of the carbon plan required by [state law] and future IRPs,” the NCUC’s order states.
Regulators also asked Duke to revise its natural gas forecast data and to model scenarios that include what prices could be under supply constraints. Duke and Dominion Energy canceled plans to build the Atlantic Coast pipeline last year after a series of legal battles, and the proposed Mountain Valley pipeline, which would carry gas from West Virginia into Virginia, faces hurdles, as well.
“Artificially low natural gas prices and constrained pipeline capacity for these new [combined cycle] generation plants is a serious matter,” the commission’s order states.
Duke should consider developing a generation portfolio that “includes natural gas import restrictions or less reliance on [Dominion South Point] gas,” it said. The Dominion, or Eastern Gas, South Point is in the Appalachian Basin near Pittsburgh.
Environmentalists said they were pleased with the commissions’ actions.
“The NCUC has made the right decision in requiring Duke to start moving away from its business-as-usual resource planning, especially by directing Duke to forecast gas prices more accurately and to reflect its true costs and volatility, which has a serious impact on people’s budgets,” said Dave Rogers, the Sierra Club’s Southeast deputy regional director for its Beyond Coal campaign.
“We are fully focused on developing a proposed carbon plan,” said Duke Energy spokesperson Bill Norton told E&E News.
Duke has pledged to work with others in North and South Carolina and looks forward to “commissions in both states to hear our proposals for developing the best path forward that accelerates our clean energy transition while continuing to prioritize affordability and reliability for our customers,” he said.
Is Biden to blame?
The historic nature of natural gas has been one of volatility and unpredictability. The nation has been used to low prices for more than a decade, however.
“There’s an amazing story of how seriously low natural gas prices have changed the economics tremendously in the energy sector,” said Paul Patterson, a utility analyst with Glenrock Associates LLC. Liquefied natural gas operations such as Cove Point, an LNG shipping terminal in Maryland, were originally intended to import, not export gas, for example.
Even so, the Southeast — like other regions — is grappling with fluctuating gas prices amid a post-pandemic supply squeeze.
As the economy recovers, significant increases in energy load haves led to higher and more volatile prices for natural gas and coal, said Brian Child, TVA’s vice president of enterprise planning, during a virtual board meeting held on Nov. 10.
“The strong economy is driving higher sales,” Child said.
Kevin Doyle, with the Consumer Energy Alliance, placed blame squarely on the Biden administration. Restricting domestic energy production, delaying drilling permits and canceling the Keystone XL pipeline have contributed to tighter supplies, he said.
Doyle said the United States can cut CO2 emissions and have a robust energy supply at the same time, but the current federal government is standing in the way of that.
“The federal government continues to put up roadblocks to making affordable, reliable energy more difficult,” said Doyle, vice president of state affairs for CEA, whose membership includes oil and gas producers and gas utilities.
“It is unconscionable that we are considering policies to make energy sources even scarcer at home,” said Doyle, referring to Biden’s carbon-cutting agenda that would further limit gas in favor of renewables.
The oil crunch started before Biden took office, however. The coronavirus pandemic shutdowns of 2020 included oil producers idling operations globally amid falling demand. OPEC+, the cartel of oil-producing countries, cited the possibility that another viral wave such as the Omicron variant could lead to lockdowns this winter as the reason for maintaining production limits.
Inflation is another culprit, driving up energy prices roughly 30 percent, according to the Consumer Price Index. And executives at some public oil and gas firms said shareholders want them to pump the brakes on expanding production.
It’s market forces, not climate policy, holding back the oil and gas industry, according to two experts from Third Way, the center-left think tank (Energywire, Nov. 24).
“Global climate policies have not substantially removed oil demand yet, nor are they likely to do so next year … and therefore transition risk still remains hypothetical,” wrote Ellen Hughes-Cromwick, a senior fellow at Third Way, and Amy Myers Jaffe, managing director of the Climate Policy Lab at Tufts University’s Fletcher School.
‘I think we can manage’
Regardless of where prices head next, states across the region are taking action to ensure adequate supplies.
In Florida, regulated electric companies won approval from state regulators earlier this year to collect more money from customers in fuel costs to pay for rising prices. Florida Power & Light Co., the state’s largest electric company, and Tampa Electric recently returned to the state Public Service Commission, saying those prices are even higher now, requiring them to ask for even more money.
Regulators unanimously signed off on FPL’s request yesterday after hearing from clean energy advocates who asked that the state’s largest electric company expand and better market its energy efficiency programs to reduce fuel consumption and cost. That will save customers money on their monthly bills.
Regulators acknowledged the request but said it would be discussed in another docket. Meanwhile, a conversation between PSC Chair Gary Clark and FPL’s lawyer Maria Moncada showed how volatile and unpredictable natural gas prices can be.
To be clear, Clark asked Moncada if FPL had factored in reports from just a few days ago that a milder winter would lead to a drop in fuel prices. Moncada said she had, and that FPL had held off on asking the PSC to collect more money since September.
“Those are forecasts from the last four days,” she said at a PSC agenda conference yesterday. “None of us can predict what’s going to happen.”
Florida utilities must tell the PSC if fuel costs are 10 percent higher or lower than what the agency has already approved for that year. Electric companies can file for a mid-course correction once that threshold is reached.
Moncada said FPL had sent the PSC a letter in September and October saying that was the case but wanted to wait it out in case prices fell again.
“We wanted to see what would happen,” she said.
By November, “we did reach a point where, as they say, you have to fish or cut bait,” Moncada said, in regard to petitioning to collect more money from customers starting next year.
Duke Energy Florida warned of the same but hasn’t filed a formal request to collect more dollars.
Meanwhile, Duke yesterday sent information to customers on how to conserve energy to save money during the winter months.
TVA, meanwhile, already has contracted for all its natural gas supplies for the coming winter, and roughly 80 percent of its fuel has been hedged.
In Georgia, the state House Energy, Utilities and Telecommunications Committee listened to officials from the natural gas and electricity sector talk about gas supply and prices during the Legislature’s special session.
Committee Chair Don Parsons (R-Marietta) said he didn’t want to point fingers and acknowledged that likely multiple reasons were behind the higher prices. He was curious about whether the power sector’s shift toward natural gas had played a role, however.
“I know there’s been a significant shift away from coal, so it has to have some influence on it,” he said during the meeting, which was broadcast online.
Tom Newsome, director of utility finance for the Georgia Public Service Commission, said Southern’s Georgia Power Co. got roughly half of its electricity from natural gas last year, putting it roughly in the middle of its sister utilities in Alabama and Mississippi.
Fuel costs make up roughly 15 to 20 percent of a Georgia Power customer’s bill, Newsome said. The amount customers are paying has risen about $3.50 to $4 a month now.
As temperatures drop, some state elected officials recently asked electric and natural gas officials whether they have enough supply to keep the lights on and the heat running through the winter — and how much that will hit customer wallets.
Company CEOs said this fall that an increased dependency on natural gas has contributed to rising bills as fuel prices have gone up. At the same time, keeping a diverse generation portfolio, locking into long-term fuel contracts and gas storage have prevented what’s known as rate shock for customers.
“I think natural gas will be a little more volatile, but it’s something I think we can manage,” said Southern Co. CEO Tom Fanning in an interview.
Also, natural gas proponents tout the Southeast’s strategic advantage of having several pipelines that connect the region to a variety of natural gas reserves. Forecasts also show that the rising prices are temporary and should level off next year, company officials have said.
“It’s actually not surprising. The volatility used to be there before the age of fracking; it was much more commonplace,” said Patterson.
