Duke Energy’s Epic Fails: $11.6 Billion in Scrapped Projects Since 2013

In July, Duke Energy and Dominion Energy canceled the $8 billion Atlantic Coast Pipeline. Six months earlier, Duke and three partners canceled the $1 billion Constitution Pipeline. These surprising decisions – made shortly after both ventures seemed assured of going forward – sent shock waves through the industry, with Dominion selling off much of its natural gas infrastructure, even as Duke clings to its plans to spend billions on more projects to supply gas for electricity generation.

But maybe the pipelines’ failures shouldn’t have been so surprising.

Since 2013, Duke and its partners have pulled the plug on an estimated $11.6 billion of failed projects. EWG’s analysis estimates that Duke’s share of losses from those failures is more than $4.3 billion.1 That’s not counting the $3.5 billion cost – $2 billion more than projected – of its coal-to-gas plant in Edwardsport, Ind., which has been plagued by scandal and failed to deliver affordable and efficient electricity.

Such staggering losses and overruns could send a company’s finances reeling. But Duke – the nation’s largest investor-owned electric utility, headquartered in Charlotte, N.C. – has continued to reap record profits, in part because its government-protected monopoly status allows it to pass on to ratepayers much of the costs of its failures.

In June, Indiana regulators ruled that Duke could permanently add charges to customers’ bills to cover three-fourths of the cost of the Edwardsport boondoggle, or $2.6 billion. Regulators in other states in Duke’s vast service territory have allowed the company to stick ratepayers with an additional $2.6 billion for other failed plants.

For decades, Duke customers will be paying for these mistakes:

  • Edwardsport Coal Gasification Plant, Indiana: $2.6 billion
  • Crystal River Nuclear Plant, Florida: $1.3 billion
  • Levy Nuclear Plant, Florida: $800 million
  • Lee Nuclear Station, South Carolina: $517 million

North Carolina customers are also paying $787 million to clean up Duke’s toxic coal ash pits, and this month, Duke will ask regulators to let it charge customers $8 billion more to finish the cleanup.

The Atlantic Coast Pipeline was only 6 percent complete when aborted. If it had gone online, Duke and Dominion could have sought approval to pass on the cost to customers in Virginia and the Carolinas. Duke had spent $1.6 billion on the pipeline before soaring costs and protracted legal battles killed it. But Duke’s finances won’t suffer much.

Wall Street analysts consider the pipeline’s cancellation a one-time hit and still view Duke as a sound investment, thanks to its 7.7 million captive customers and its plans to raise their rates. Duke also apparently hedged its bet on the pipeline’s future last November, when it completed a “forward sale” of stock that could return more than $2.4 billion by the end of this year.

Where the Money Is

Why does Duke keep pursuing big and risky investments in dirty and dangerous energy sources when clean, safe, renewable resources – solar, wind, storage batteries and increased efficiency – are already cost competitive or cheaper, and getting cheaper every year?

As “Slick” Willie Sutton reportedly said when asked why he robbed banks: “That’s where the money is.”

Duke’s government-protected monopolies are relics of an era when utilities held an iron grip on the generation of electricity. In return for extending service to everyone in their exclusive territories, monopoly utilities are guaranteed a “reasonable” rate of return, through ratepayers’ monthly bills, on investments in new power plants and distribution grids.

The bigger the investment, the bigger the return and the more profit for shareholders. If the project fails or is crippled by cost overruns, utilities flex their political clout to get regulators’ approval to let them recover the costs from customers.

Duke’s failed projects constitute a scrap heap of high-cost, high-risk, high-reward gambles that crapped out. But they’re not really gambles, because Duke is playing with house money. As long as politicians and regulators sanction the customer-gouging, socially unjust, health-threatening and environmentally destructive monopoly model, and as long as Wall Street rewards it, Duke and other profit-first utilities will keep rolling the dice.

(See the Appendix for a list of other notable boondoggles by big utility companies.)

‘Net-Zero’ Carbon by 2050 – But How?

In May, Duke announced its goal to reach “net-zero” carbon emissions by 2050. In September, it will submit to North Carolina regulators its latest Integrated Resource Plan, outlining its energy mix for the next 15 years. And in December, the state will consider recommendations on carbon policy and utility regulatory reform, growing out of last year's Clean Energy Plan, that could push Duke toward more renewables ¬– although on its second-quarter earnings call, CEO Lynn J. Good said the company doesn’t see offshore wind power as viable for at least a decade.

But Duke is maddeningly vague about how it will get to “net zero” electricity.

Its most recent Climate Report views the transition as difficult without new natural gas plants or pipelines and says it will “depend on our ability to site, construct and interconnect new generation, transmission and distribution resources at an unprecedented scale.” The report indicates Duke is banking on the doubtful viability of carbon-capture technology, the iffy availability of a new generation of “modular” nuclear reactors, and the pipe-dream prospect of using reactors to produce hydrogen – all schemes to boost profits through expensive capital projects.

Clearly, Duke isn’t going to stop gambling on costly and risky projects any time soon. Unless it does, its string of epic fails is a good bet to grow longer.

The Atlantic Coast Pipeline

Duke held a 47 percent share in Atlantic Coast Pipeline LLC, or ACP. The 600-mile pipeline was intended to carry fracked natural gas through parts of West Virginia, Virginia and North Carolina. The original cost estimate was $4.5 billion. Planning began in 2014, and the Federal Energy Regulatory Commission, or FERC, approved the project in 2017.

But then came a seemingly endless series of legal challenges, including:

  • In 2017, the Fish and Wildlife Service denied the pipeline a permit because it threatened a freshwater mussel protected by the Endangered Species Act. ACP went directly to a deputy secretary at the Interior Department, who directed the agency to issue the permit. In 2019, a federal appeals court threw out the permit, saying “the agency appears to have lost sight of its mandate ‘to protect and conserve endangered and threatened species and their habitats.’ ”
  • In 2018, the Sierra Club, Defenders of Wildlife and the Virginia Wilderness Committee won a stay from the same appeals court, stopping construction for two years. That decision blocked ACP from tunneling under the Appalachian Trail.
  • In 2019, a predominantly black community in Buckingham County, Va., sued to block a permit for a pipeline compressor station. The appeals court ruled against ACP, saying the facility would have “a disproportionate adverse impact on economically disadvantaged or minority communities.”
  • In June, the Supreme Court overturned the appeals court decision that blocked tunneling under the Appalachian Trail, but ACP still needed eight more permits to move forward. Three weeks later, Duke and Dominion announced the pipeline was dead.

Legal obstacles aside, the pipeline simply wasn’t needed.

In July, a Synapse Energy Economics analysis of Duke’s integrated resource plans, commissioned by the Southern Environmental Law Center, found that electric demand is flat and the Carolinas have enough gas already. The pipeline, whose estimated cost had ballooned to $8 billion, was destined to become a “stranded asset” – another white elephant.

Also, Virginia and North Carolina have adopted aggressive policies to cut carbon emissions and expand wind and solar. In response, Dominion, which is based in Richmond, Va., sold off its interstate pipeline business for $10 billion. Duke took a $1.6 billion hit, missing its earnings-per-share goal, and said it will spend $2 billion on other new projects, in the near term, it hopes will be profitable enough to fill the gap.

The make-up spending plan includes investments in new utility-scale solar and in reinforcements of the electric grid,2 some of which may be needed. Whether it’s the most cost-effective way to address climate change and affordability and reach “net-zero” carbon remains to be seen.

The Edwardsport Coal-to-Gas Plant

Burning coal to produce synthetic gas was once touted as “American coal power's last, best chance.” The problem is the cost: In 2014, an analyst said: “I think you almost could compare [coal-to-gas plants] to nuclear plants, because they have a very high capital cost ... have relatively high fixed costs once they’re operating, and you still have uncertainty associated with the carbon capture [technology].”

By the time of that assessment, U.S. utilities had scrapped plans for dozens of coal-to-gas plants, leaving just two under construction: Southern Company’s ill-fated Kemper Project in Mississippi (see Appendix) and Duke’s Edwardsport plant.

Edwardsport’s initial cost estimate, in 2006, was $1.3 billion to $1.6 billion. Eight months later it was nearly $2 billion; by 2012, more than $3.5 billion. Duke declared the plant in service in 2013.

Throughout construction, corruption was rampant.

Duke executives engaged in prohibited communication with the chair of the state regulatory commission. During the regulatory process, Duke hired the administrative law judge overseeing the proceeding. For helping grease the hire, the commission chair was indicted on three felony counts of official misconduct. Duke’s second-in-command resigned after the Indianapolis Star exposed his cozy relationship with the chair and left with a $10 million golden parachute.

Duke pushed through legislation to shift construction costs to ratepayers and secured $440 million in federal, state and local tax credits, because the company knew that, as the first large-scale commercial plant of its kind, Edwardsport would be more expensive than a conventional natural gas plant.

Despite the scandals and overruns, regulators approved the plant. Lawmakers amended Indiana’s ethics statute so the commission chair would not serve time in prison. In 2013, in a settlement with citizens’ groups, regulators capped the amount Duke could pass on to ratepayers at $2.6 billion – a decision affirmed in June, when the costs of the plant were permanently added to customers’ bills.

Like the Atlantic Coast Pipeline, Edwardsport wasn’t needed. Two years before it opened, the amount of wind power in Indiana was about three times Edwardsport’s capacity. In Duke Indiana’s most recent rate-hike case, an expert witness used the company's own data to show:

  • Because of technical problems, Edwardsport rarely runs at full capacity.
  • It costs twice as much to operate as the cost of new wind-plus-storage projects in northwest Indiana.
  • The amount of power used to run pollution control and other equipment is nearly nine times more than that of a conventional natural gas plant.

The Constitution Pipeline

The Constitution Pipeline, which would have delivered natural gas to customers in rural Pennsylvania and New York, was announced in 2012 and approved by FERC in 2014. The principal partner was the Williams Companies of Oklahoma. Piedmont Natural Gas, which Duke acquired in 2016, held a 24 percent interest. The initial cost was estimated at $700 million.

Williams angered property owners and New York officials by moving too aggressively. Before getting the state water agency’s permit, Williams began cutting trees, the debris clogging streams. In 2016, the state denied the permit, a decision upheld by a federal appeals court.

Citizens along the pipeline’s path flooded FERC with objections to the project, saying it would fell 700,000 trees, cross more than 250 streams without adequately protecting habitats and water quality, and promote fracking, worsening the climate crisis.

In August 2019, FERC ruled that New York had taken too long to deny the water permit, putting the project back on track. But that year, Gov. Andrew Cuomo unveiled a Green New Deal that envisioned moving away from fossil fuels altogether. That must have concerned investors, because the pipeline still needed additional state and federal permits.

In February, Williams cancelled the pipeline. Delays had increased the projected cost to about $1 billion. The Charlotte Business Journal reported that Duke had spent about $85 million.

The Lee Nuclear Station

The Lee Nuclear Station was a proposed twin-reactor power plant in Cherokee County, S.C. When Duke first approached regulators in 2006, it touted a nuclear renaissance – a recurrent industry fantasy that has never materialized – and said the plant would be a “least cost resource." But it also noted how financially risky nuclear construction is.

Duke pleaded that it needed assurance it could later recover pre-construction costs from ratepayers because the plant would mean lower electricity rates. In 2007, Duke pushed through legislation that ensured future cost recovery. When Duke applied to the federal Nuclear Regulatory Commission, or NRC, for a license, it estimated the cost would be $5 billion to $6 billion.

By 2011, construction had not begun, but Duke had raised the estimate to $11 billion.3 The Fukushima disaster that March cast a pall over the so-called nuclear renaissance. Duke also faced inconvenient truths: Electric demand had dropped significantly, and nuclear power couldn’t compete with the glut of cheaper natural gas flooding the market. Lee was in limbo.

Duke didn’t receive a construction and operating license from the NRC until December 2016. Three months later, Westinghouse, maker of the reactors planned for Lee, was driven into bankruptcy by huge cost overruns at the V.C. Sumner and Vogtle nuclear plants under construction in Georgia. (See Appendix.)

Duke, which had assured regulators it was carefully monitoring the Georgia situation, said the bankruptcy was unexpected and asked for permission to cancel the plant. Ratepayers were stuck with $517 million for an empty lot, but Duke still claimed nuclear power was a “cost effective” option.

The Levy and Crystal River Nuclear Power Plants

In 2012, Duke merged with Progress Energy, which served parts of the Carolinas and Florida. Progress had earlier pushed through Florida legislation to allow for costs of nuclear plants, both before and during construction, to be charged to ratepayers on a pay-as-you-go basis.

The reactors slated for Progress’ nuclear plant in Levy County, Fla., were the same flawed models that bankrupted Westinghouse and forced cancellation of Duke’s Lee plant. Predictably, Levy ran into the same problems.

In 2006, Progress’ original estimate for Levy was $5 billion to $6 billion. By the time of the merger, the price tag had swelled to $24 billion and the projected in-service date had been pushed back eight years, to 2024.

Undeterred, Duke continued to seek a license from the NRC. But after it was granted in 2016, Duke announced it would halt production – again insisting that nuclear power remained a viable option for the future. Of Progress’ pre-merger expenditure of $1 billion, Florida regulators allowed Duke to charge customers $800 million for a plant that never delivered a kilowatt of electricity.

Three years before the merger, Progress began replacing the steam generators at its nuclear plant in Crystal River, Fla. That involved opening the containment structure, which in a reactor accident would prevent the escape of radioactive steam. To save money, Progress moved too quickly, without expert oversight, and damaged the containment structure.

After the merger, an independent review found that repairs could cost more than $3 billion. Knowing state law allowed cost recovery, in 2013 Duke shut the plant down. Duke Florida customers will pay $1.3 billion – about $170 million a year for 20 years – for Progress’ blunder.

The Future

Duke knows the future of its business model is precarious. In its annual report to the federal Securities and Exchange Commission, Duke warns investors that its profits could be threatened by the climate crisis, tougher clean air regulations, a serious nuclear accident and shrinking demand for electricity as customers go solar and invest in efficiency.

Duke and other investor-owned utilities are required by law to maximize shareholder profits. But the energy market’s inexorable transition to renewables, and the climate, public health and pollution risks of natural gas plants, pipelines and nuclear reactors, mean Duke’s reliance on those resources is not in the long-term interest of its shareholders – or its customers.

To push Duke and other utilities into the clean energy future, politicians and regulators must disrupt the monopoly model that has ceded control of energy to profit-first corporations.

  • Electricity rates should be tied to efforts to increase efficiency and promote rooftop and community solar.
  • Stockholders should bear the costs of big capital projects, to counter the cavalier attitude toward blowing ratepayer billions and recovering it through utility bills.
  • Regulators should exercise oversight of utilities’ planning to ensure focus on delivering least-cost and necessary service to customers, not simply increasing profits.

Notes

1 Duke held a 47 percent share in the Atlantic Coast pipeline, and at the time of cancellation had spent $1.6 billion. Through its subsidiary Piedmont Natural Gas, it held a 24 percent share in the Constitution Pipeline, whose estimated cost had risen from $700,000 to $1 billion, and Duke had spent about $85 million.

2 Duke’s “grid modernization” scheme in North Carolina has been rejected twice – first by the legislature, then by regulators. Duke claims the plan would prepare the grid for more renewables, but public interest groups say it would actually impede the growth of renewables and storage.

3 The Charlotte Business Journal noted that financing costs would raise the Lee plant’s price to more than $14 billion.

Appendix: Failed Projects Are Rife in the Utility Industry

When it comes to epic failures in the utility industry, Duke has plenty of company.

The industry’s track record of boondoggles is one reason investors are shying away from mega-projects, particularly new, untested designs never built at commercial scale. To get such projects off the ground, utilities have gotten lawmakers to shift construction risks to ratepayers a with pay-as-you-go mechanism called CWIP – construction work in progress – because smart investors won’t finance these engineering experiments unless customers are turned into the utilities’ personal bank.

"Many utilities have already started to focus their capital plans away from mega-projects and more toward smaller, more modular projects," Scotiabank analyst Andrew Weisel told Utility Dive. "You're not going to see many utility holding companies placing big investments … on large-scale midstream projects. … [S]everal utilities have learned the hard way that it might not be as easy as it used to."

Here is just a sample of other utilities’ notable failures and boondoggles.

Utility Project Initial Cost Estimate Current/Final Cost Estimate Reason for Failure Status
Southern Company Vogtle Nuclear Plant $14.3 billion $27.5 billion Untested new design; cost overruns; construction delays Still under construction
SCANA and Santee Cooper V.C. Summer Nuclear Plant $11.5 billion $25 billion Untested new design, cost overruns; construction delays Cancelled
Southern Company Kemper Coal Gasification Plant $1.6 billion $7.5 billion Untested new design; cost overruns; construction delays Operating as natural gas plant only – no coal gasification
Williams Company Northeast Supply Enhancement Pipeline $1 billion $1 billion Damage to water quality; New York state and New York City energy policy; not needed Project in limbo for the moment
Xcel Energy Life-cycle extension and uprate of Monticello Nuclear Plant $274 million $748 million Gross mismanagement Regulators allowed recovery of capital costs but not return on investment

Source: EWG, from news articles and regulatory filings