Big Oil Defeats Big Wind as Trump’s Uranium Fuel Policies Disintegrate

August 3rd, 2018 - by admin

Dan Gearino / Inside Climate News & Stephen Lee / BNA News – 2018-08-03 00:33:02

Wind Project Defeated by Big Oil
AEP Cancels Nation’s Largest Wind Farm:
3 Challenges Wind Catcher Faced

Dan Gearino / Inside Climate News

(July 30, 2018) — American Electric Power last week abandoned its plan to build the largest wind farm in the United States, a victim of a complex mix of political, regulatory and market challenges.

The giant utility company gave up after the Texas Public Utility Commission rejected the 2,000-megawatt, $4.5 billion project known as Wind Catcher.

The project faced stiff opposition from interest groups whose formidable regional influence is bolstered with fossil fuel money. And it faced a shifting financial landscape, with cheap natural gas and shifting tax policies casting doubts on its economic merits. It also needed 350 miles of controversial new transmission lines, often a daunting obstacle to large-scale grid modernization.

Its demise, while a big deal in the world of wind energy, probably doesn’t signal trouble ahead for the wind industry at large, which is thriving, analysts said.

“Just in general, it’s very difficult to get multiple regulatory jurisdictions to come to a conclusion and continue to have the economics make sense,” said Andrew Bischof, an analyst who covers utilities for Morningstar. Wind Catcher needed regulatory approval required from Texas and three other states: Arkansas and Louisiana, which gave it the green light, and Oklahoma, which had not yet decided.

Texas Gets Cold Feet
Texas is the country’s wind energy leader, but it seems to be increasingly skeptical of renewable energy, said David Spence, a professor of law, politics and regulation at the University of Texas at Austin.

“Up until recently, the general zeitgeist here has been we’ve been really proud that we’re a big hub for wind,” he said. “That’s how (former Gov.) Rick Perry was until he got involved in national GOP politics.”

Most of the state is on its own grid and has deregulated its electricity market, meaning regulators would not have a say in this type of decision. However, the AEP project serves two small parts of Texas that are in the much larger Southwest Power Pool grid, which runs from the South up through parts of the Midwest, and those parts of the state have traditional utility regulation, giving officials the power to accept or reject the plan.

Before voting it down, Texas commission members devoted much of their debate on questions about whether Wind Catcher would deliver the promised cost savings to consumers.

Much of this argument came down to a review of recent forecasts that low natural gas prices are here to stay. Wind Catcher’s opponents seized on this, and regulators seemed to agree.

Spence questions this reasoning, saying that gas prices are volatile and wind prices are competitive. He cites a report from Lazard, an investment bank, showing that the levelized cost of wind energy, a key measure of its competitiveness, is continuing to go down, dropping 6 percent last year.

Even if Texas had supported the plan, AEP still needed approval in Oklahoma, where a decision was still pending. And there was strong pushback there, including from the state’s attorney general and fossil-fuel-connected groups.

Wind Catcher faced opposition from Americans for Prosperity, which was founded by the Koch Brothers, and the Windfall Coalition, whose co-founders include energy executive Harold Hamm. They were making their cases in states where the oil and gas industry has substantial influence.

“In its current form, the Wind Catcher Energy Connection Project is a risky scheme that is simply not a good deal for Oklahomans,” John Tidwell, Americans for Prosperity’s Oklahoma director, said in a statement earlier this month.

Some of the opposition in Oklahoma was also from people who live near the proposed transmission line. This underscores a familiar point: Transmission lines almost always run into local objections, but they’re needed to get electricity from wind-rich areas to population centers.

Tax and Regulatory Uncertainty
A shifting landscape for federal taxes and regulations also undermined the project.

Despite the long odds, AEP initially projected that there would be a carbon tax affecting fossil fuels at some point in the wind farm’s life, which would make the project more cost effective compared to natural gas.

The company changed this assumption under scrutiny from other parties, so the cost analysis now assumes that there will be no carbon tax for decades.

The Trump administration’s corporate tax cut also reduced the project’s federal tax rate in a way that diminishes the effects of the production tax credit for tax-equity investors in big wind projects. The tax credit, meanwhile, is set to be phased out. The upshot is to reduces the projected tax savings the project, making its electricity more expensive, which further hurt AEP’s case.

Adding to the uncertainty is the Trump administration’s challenges to the Obama-era Clean Power Plan, which would have driven up demand for alternative energy sources to replace coal power plants.

What’s Next?
Wind Catcher’s challenges were specific enough to its circumstances that the failure is not likely to affect how developers approach other projects, said Jay Orfield, senior energy analyst for the Natural Resources Defense Council.

He noted that the industry’s capacity has been growing year to year and that there are other projects in various stages of development that would be nearly as large or larger.

In the first fast half of this year, $17.5 billion was invested in wind energy projects, up 121 percent from the same period last year, according to Bloomberg New Energy Finance. Some of the increase is because companies are rushing to begin projects in time to take advantage of the federal production tax credit, which will phase out by 2020.

AEP was developing Wind Catcher with Invenergy, a Chicago-based company. There is still a chance that Invenergy could come back with a new version of the project, or have several smaller projects, with or without AEP. Invenergy did not respond to a request for comment.

Local leaders in the Oklahoma Panhandle are pinning their lingering hopes on the idea that some version can be salvaged. The mostly rural region has struggled to attract employers, and this would have been by far the largest investment in its history, with a projected 4,000 construction jobs and a dramatic increase in tax revenue for local governments.

Its demise is still sinking in for Michael Shannon, director of the region’s economic development office. “I’m stunned,” he said, adding, “There has to be a Plan B.”

Trump’s Uranium Review Rattles Nuclear Utilities
Stephen Lee / BNA News

WASHINGTON (July 30, 2018) — The Trump administration’s hard look at uranium imports is already rattling nuclear utilities’ fuel-purchasing decisions.

The Commerce Department said July 18 it would launch an investigation, at the behest of uranium mining companies Energy Fuels Inc. and UR-Energy Inc., into whether US overreliance on imported uranium threatens national security.

Although it is still too early to measure the Commerce probe’s specific impacts, John Keeley, a spokesman for the Nuclear Energy Institute, confirmed that some utilities “may be choosing to defer their contracting until there is more certainty with the outcome of the Department of Commerce’s review.”

To make nuclear fuel, uranium is extracted from rock and enriched, before being made into pellets that are loaded into assemblies of nuclear fuel rods.

Demand Exists
The demand is there. Most utilities’ uranium needs are locked down for the next couple of years, but generally not beyond 2020 or 2021, said Treva Klingbiel, president of uranium analyst TradeTech LLC in Englewood, Colo.

If the Commerce Department delivers a quota mandating that 25 percent of US uranium must be domestically produced, utilities might be barred from taking foreign shipments for which they’ve already contracted. In that case, they might have to argue that uncontrollable events have voided their purchase agreements.

Energy Fuels of Lakewood, Colo., and UR-Energy of Littleton, Colo., had earlier asked the Trump administration for a quota capping foreign uranium imports at 75 percent of US needs.

. . . But the Math Doesn’t Work Out
The utilities would then have to turn to domestic uranium suppliers, but right now, there’s not enough domestic supply to satisfy the 50-million-pound national demand. Last year, US producers accounted for only 1.1 million pounds. A 25 percent tariff would mean the sector would have to quickly ramp up roughly twelve-fold.

Uranium stockpiles of that size do sit underneath US soil. The problem is that mining companies can’t afford to extract it at current prices of between $25 and $26 a pound, Paul Robinson, research director at the Southwest Research and Information Center in Albuquerque, N.M., told Bloomberg Environment. For them, the economics only make sense if uranium hits $40 to $60 a pound.

First Energy Corp. isn’t worried because its future uranium supplies are already contracted, but the company is also swiftly exiting the nuclear sector, said Tricia Ingraham, a company spokeswoman.

Nuclear utilities Exelon Corp. and Entergy Corp. declined to comment.

The Commerce Department’s action could also be a prelude to a tariff on foreign uranium. Klingbiel noted that tariffs seem to be a favored policy tool for the Trump administration.

That introduces yet another wild card into utilities’ decisions, according to Tim Gitzel, CEO of uranium giant Cameco Corp in Saskatoon, Saskatchewan, Canada.

“That’s probably not good for US utilities,” Gitzel said during a July 26 earnings call. “It certainly has added to confusion in the market. We have to see a few new cards.”

Miners Shaken Up, Too
The administration’s moves are also shaking up the supply side. Gitzel said a 25-percent quota is “a bit aggressive” because of how much more uranium it would require the US to produce.

Cameco, the biggest uranium producer in the world, has US mines that could probably get up and running in 18 to 24 months, Gitzel said. But he also said that wouldn’t make economic sense unless the mineral hit $50 to $60 a pound.

Already, uranium prices are “unsustainably low,” Gitzel said. That’s why the company said July 25 it’s keeping its McArthur River mine and Key Lake mill, both in Saskatchewan, shut down indefinitely. The company previously said those facilities might reopen later this year.

“It doesn’t make economic sense” to keep the mine open, Gitzel said.

A Small Slice of the Pie
US uranium production represents only 1.8 percent of the world’s total, and production fell 64 percent during the first quarter of 2018, according to the Energy Information Administration.

Right now, only three uranium mines are operating in the US: one owned by Energy Fuels, one by UR-Energy, and a third by Peninsula Energy Ltd. of Australia.

A fourth mine, also owned by Energy Fuels, is being evaluated and should soon be ready to start operating, Paul Goranson, Energy Fuels’ chief operating officer, told Bloomberg Environment.

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