ANALYSIS: ‘Broken Promises, Busted Budgets’ Point to the End of Energy Megaprojects
A small flurry of recent news reports, spanning the range of traditional energy technologies, is pointing to a startling and possibly transformative conclusion: the era of centralized nuclear, coal, oil, and natural gas megaprojects may be drawing to an end.
“I think people are going to think twice about these type of cutting-edge projects,” said Glenrock Associates analyst Paul Patterson, in an E&E News report [subs only] that traced the recent or imminent collapse of two nuclear construction projects and one “clean” coal development in the southeastern United States. “That goes for utilities and policy-makers alike.”
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“Vogtle. Kemper. V.C. Summer. A decade ago, this trio of sprawling power projects signaled the next wave of cleaner baseload energy that would keep air conditioners and the economy humming in the fast-growing Southeast,” E&E notes, in a story picked up by the Institute for Energy Economics and Financial Analysis. “Now, all three have become symbols of broken promises and busted budgets.”
Are Utility Megaprojects Over?
While the projects all have their own unique characteristics, “lingering problems faced by all three power projects and the continuing transformation of the electric power industry begs a question: Is the era of the utility megaproject over?” asks reporter Jeffrey Tomich. “For at least certain types of multi-billion-dollar projects that require a decade of lead time, such as large-scale nuclear plants, the answer seems to be yes, at least for the foreseeable future.”
The Mississippi Public Service Commission finally pulled the plug on the Kemper CCS facility in June after its US$2.3-billion budget ballooned to $7.5 billion, with no end in sight. In South Carolina last month, two project partners stepped away from the two 1.1-gigawatt generators at the Virgil C. Summer nuclear station after construction costs skyrocketed from $6 billion to $25 billion.
And while the Vogtle nuclear station in Georgia is still under construction [advice to reader: check Twitter], its cost has nearly doubled from $14 to $25 billion, and its target completion date has been pushed back to 2021. Like the V.C. Summer project, its timing and costs were thrown into doubt when its main contractor, Westinghouse, filed for bankruptcy in March.
Atlanta-based Southern Company, already rocked by the two other cancellations, believes its subsidiary, Georgia Power, should still carry on with the project. “From a lot of scenarios, going forward with nuclear may make sense,” said CEO Tom Fanning.
Accurate Pricing Isn’t a Strong Suit
But “Georgia Power residential customers already are paying financing costs of the Vogtle expansion,” the Atlanta Journal-Constitution reports, “with the ultimate effect of construction costs on bills yet unclear.” And in a withering opinion piece, business columnist Matt Kempner is second-guessing whether Southern and Georgia Power can deliver a reliable cost estimate for the project.
“Accuracy hasn’t been a strong suit of the power giants in recent years,” he writes, pointing to Kemper and Vogtle as the “exactly two” megaprojects Southern has taken on in the last decade. “As each project struggled, Southern and its subsidiaries continued to underestimate the magnitude of the overruns,” he writes. “Independent monitors for the Georgia Public Service Commission regularly [issued warnings] about rising Vogtle costs that were more accurate than Georgia Power’s reassurances about stability.”
Georgia Public Service Commission member Tim Echols said the project can still survive if Westinghouse’s parent company, financially shaky Toshiba, comes through with billions of dollars in promised support. If it doesn’t, “the math doesn’t work and the Vogtle project probably terminates or gets converted to natural gas.”
From a half-dozen time zones away, meanwhile, “it sometimes seems like U.S. and European nuclear companies are in competition to see which can heap greater embarrassment on their industry,” the Financial Times notes in today’s Energy Source newsletter. “The U.S. plants risk becoming an even bigger fiasco than those involving the European Pressurized Reactor at Flamanville in France and Olkiluoto, Finland, which, although years late and billions of euros over budget, at least look likely to be completed in the next couple of years.”
Overruns a Feature, Not a Bug
The E&E/IEEFA article points to a bigger trend afflicting megaprojects of all sorts, not just nuclear projects.
“The price tag for Duke Energy Corporation’s 618-MW Edwardsport Power Station, a coal gasification power project in Indiana completed in 2013, was almost twice its expected $1.9-billion estimate,” Tomich notes. “And the Prairie State Energy Campus, a 1,600-MW supercritical coal plant in southern Illinois developed by Peabody Energy Corporation, cost more than twice its initial $2-billion cost estimate.”
In a repeat of a 2014 study, looking at 100 electricity and water megaprojects around the world, consultants at Ernst & Young found they were on average $2 billion over budget and two years behind schedule. That’s not a conclusion that will sit well with utility regulators.
“From a regulator’s standpoint, your No. 1 thing is reliability, and I think there will always be a place for large baseload projects if you can prove the need,” said consultant Kevin Gunn, a former chair of the Missouri Public Service Commission. But the key question today is something different: “Is there enough [existing baseload capacity] where you don’t need to build anymore?”
Oil and Gas: ‘Go Small or Go Home’
While the focus in the southeastern United States is on power utilities, the cancellation of the C$36-billion Pacific NorthWest liquefied natural gas development in British Columbia is also shining a light on big, expensive fossil megaprojects. The announcement “may offer a lesson to natural gas exporters: Go small or go home,” Bloomberg reports.
“With a global glut dragging down prices, liquefied natural gas suppliers including Cheniere Energy Inc. and Tellurian Inc. are looking to build smaller and cheaper. Such projects—a third of the size and a fraction of the cost of most existing terminals—offer a competitive edge for supplying emerging markets like the Middle East and Latin America, where customers are seeking intermittent deliveries of small amounts of the heating fuel.” Other examples include the Coral LNG venture in Mozambique, and the Woodfibre project in B.C.—which analysts assessed late last year as a one-off investment, not the leading edge of the previous provincial government’s long-awaited LNG boom.
Pira Energy gas and power analyst Ira Joseph described the Petronas decision as “a reflection of the world that we are in.” He explained to Bloomberg that “the market is already crowded with projects, demand is more fragmented, and there are smaller types of buyers,” which translates into a need for smaller projects.
Pipelines: Locking In Future Demand
But last week, InsideClimate News reported that U.S. pipeline companies are spending billions of dollars on dozens of new projects to carry fracked natural gas from the Marcellus-Utica fields in Pennsylvania, Ohio, and West Virginia.
“Critics say that the financial interests of gas and electric companies—not market demand—are driving most of the new pipelines proposed for the region,” ICN noted. An investigation last month by the U.S. Center for Public Integrity and StateImpact Pennsylvania, working with National Public Radio, documented “an exceptionally cozy relationship” between the companies and the Federal Energy Regulatory Commission, which reviews and approves new pipelines. It also pointed to the “tight corporate links between the companies building the pipelines and those buying the natural gas, either to deliver it to homes and businesses or to use it to make electricity,” ICN states.
Those relationships “not only set up sure-fire profits at the expense of consumers, critics say; they also lock in long-term incentives—in the form of physical infrastructure and financial rewards—to keep burning the fossil fuels that are warming the planet.”
“It’s bad for ratepayers, it’s bad for the climate, it’s bad for the environment, but it’s really good for companies that are going to make profits,” said Senior Policy Analyst Amy Mall at the Natural Resources Defense Council.
Renewables Are Not Immune
Nor are renewable energy megaprojects immune to the long lead times, cost overruns, and shifting business propositions that plague centralized fossil and nuclear technologies. Over the last few months, University of British Columbia researchers and the Commercial Energy Consumers Association of B.C. have both questioned the business case and future cost of the Site C hydro dam on the Peace River, near Fort St. John. With 49% of British Columbians saying it should be reviewed or cancelled, the new NDP government referred the controversial project to the BC Utilities Commission last week.
To which David Vardy, who chaired the Newfoundland and Labrador public utilities board when it reviewed that province’s Muskrat Falls hydro venture, had a succinct reaction: “My comment to British Columbia is a big red sign saying ‘Stop.’ This is crazy. Don’t go ahead with this [project],” he told DeSmog Canada. The cost of Muskrat Falls rose from C$6.2 to $12.7 billion, including financing costs, and is expected to double Newfoundlanders’ electricity rates to 23.3¢ per kilowatt-hour in 2022.
“I knew this was a boondoggle,” said Stan Marshall, who took over as CEO of provincially-owned Nalcor Energy following a change in government. “It should never have been built. How many times do I have to say that? But it’s too late to stop. We couldn’t go and get a refund.”
Reach for Demand Side First
In the end, the projects all face a common threat: On E&E News, electricity practice manager Chris Nelder at the Rocky Mountain Institute cited low gas prices, falling wind and solar costs, and limited utility capital budgets as factors weighing against new gigawatt-scale generating capacity.
“I don’t think the world needs big new power plants, especially not the U.S.,” he said. “We ought to be reaching for the demand-side stuff first. That has been and always will be the cheapest solution.”