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The coal business is a different kind of energy business. Unlike crude oil, coal is not a commodity traded freely on global markets. Unlike natural gas, its price is not generally subject to volatility when winters are colder or warmer than expected. And unlike wind and solar power, its consumption is not encouraged by state renewable energy portfolio mandates for power companies or production tax credits for producers.

It is the nature of the coal business to evolve more slowly than most. Particularly in the Western states, which now account for more than half of production nationwide, mining is a capital-intensive business, with years of permitting and infrastructure development required to add capacity.

Almost 93 percent of coal consumed in the U.S. is used by producers of electric power, most of it secured through longer term contracts. And in years past, coal has been primarily used to fire base load electric power generation, resulting in fairly stable demand.

But the last few years have seen profound changes that have descended on the industry with unprecedented speed. Producers in states like Montana, which have benefited from the shift in U.S. production towards western coal as well as the export potential to markets in Asia, are looking at a future that is considerably bleaker than what was envisioned just a few years ago.

Market, regulatory and environmental challenges have clouded the outlook for major coal producers, sending the stock prices of the four largest companies plunging by 80-95 percent compared to year-ago levels. Financial challenges have beset many global commodity producers with the unwinding of the commodity boom in the last 12 months.

The International Monetary Fund’s index of all commodity prices has dropped by a third since summer of 2014. But the reversal of fortune in coal, traditionally less exposed to the boom-and-bust cycle of other energy commodities, has been especially severe. The outcome of the profound adjustments underway will be an important factor in shaping the outlook for states and regions with exposure to the industry’s fluctuations, including Montana.

Yet the fate of the U.S. coal industry depends on more than markets. Public policy decisions in three key areas – carbon regulation, infrastructure expansion and management of federal lands – will play an important role in determining the industry’s future trajectory. In fact, as troubling as the last two years have been for those who depend on the coal economy, it is the future that will be shaped by these decisions that is of greatest concern.

When the Montana Land Board voted 3-2 to approve the leasing of 570 million tons of coal to be developed by Arch Coal on state-owned land in the Otter Creek tracts in southeast Montana on March 18, 2010, expectations for the coal industry were high. That was particularly so for producers in the Powder River Basin (PRB), whose deposits straddle the Montana-Wyoming border. Even as domestic demand for coal was stagnant, the promise that high quality coal mined from very efficient surface mines in the PRB could tap into the growing Asian markets was attracting attention and investment.

In the five years that have elapsed since that announcement, the fortunes of the industry have soured significantly. A combination of changes in domestic markets, global markets, and regulatory setbacks have produced this outcome.

The Competition From Natural Gas

The domestic coal business has changed because the entire energy business has changed. Most of those changes stem from the shale oil and gas boom in the continental U.S. that began in earnest 10 years ago. It is difficult to understate the impact of the production of oil, natural gas, and natural gas liquids directly from source rock that innovations in horizontal drilling and hydraulic fracturing have enabled.

Those impacts have propagated to coal markets largely through the increased production and falling prices of natural gas. Prior to 2005, U.S. natural gas production was largely stable, with increases in domestic demand pushing up both prices and imports. Most imports were sourced from Canada and transported by pipeline.

In the pre-2005 era, plans were underway to construct expensive, liquefied natural gas (LNG) terminals to import gas from countries like Qatar, and discussions on a pipeline from the northern slope of Alaska to the lower 48 states were continuing. Huge increases in gas production from shale plays in states like Texas and Pennsylvania have ended those discussions.

The 40 percent increase in U.S. gas production that has taken place has caused wellhead prices to fall by more than half of their mid-decade levels. And because the new production is sourced closer to population centers where demand takes place, changes in delivered prices were just as dramatic.

The Recession’s Impact on Electricity Demand

The time that elapsed since the last decade’s midpoint also witnessed the most severe economic downturn since the Great Depression of the 1930s.

The contraction in economic activity during the 2007- 09 recession interrupted the growth trend in electricity consumption nationwide that had been unfolding in the recovery period since the 2001 recession. Perhaps even more significantly, in the recovery since the so-called Great Recession there has been no resumption in demand growth.

What is particularly challenging for coal-fired electric generators is the declining share of electricity demand from industrial customers. These customers are more likely to have high load factors - the percent of time when their demand for electricity is equal to their peak requirements - which are well-suited for power generated from coal. This is because of the technical and economic difficulties in ramping up and ramping down power output from coal-fired generators.

Industrial demand for electricity contracted by more than 15 percent as the recession hit. But after recouping about three-quarters of that loss immediately after the recession ended, industrial demand has entered a period of secular decline. The declining importance of high load factor industrial demand has been one of the factors allowing utilities and merchant power providers to serve markets with natural gas generators, weakening the demand for coal.

The Regulatory Challenges

Coal-fired power plants in the U.S. have also seen cost increases in recent years stemming from the cost of compliance with new environmental regulations from the U.S. Environmental Protection Agency (EPA). Of these, the most important have been Mercury and Air Toxics Standards (MATS) and the carbon emissions limits that are included in the Clean Power Plan.

The legal setback to the MATS handed down by the Supreme Court in July 2015 has come too late to meaningfully impact the investments and other changes made to coal-fired power plants. The rules set standards for mercury and other toxic air pollutants to levels achieved by the best-performing sources currently in operation. They apply to all units in operation with a capacity of 25 megawatts or greater, and went into effect for most in April 2015.

Operators of coal-fired power plants across the U.S. have developed strategies to comply with the MATS standards. The costs of the equipment needed to control acid and toxic metal emissions played a significant role in retrofitting and retirement decisions faced by coal plant operators.

The Energy Information Agency (EIA) estimates that 64.3 percent of the U.S. coal generating capacity in the electric power sector already had the appropriate environmental control equipment to comply with MATS and allow their operation past 2016. Another 5.8 percent planned to add control equipment, while 9.5 percent had announced plans to retire the plants.

Owners of the remaining 20.4 percent were faced with the decision of upgrading or retiring their plants. In 2012, these represented 1,308 coal-fired generating units in the U.S., totaling 310 GW of capacity. Assuming the EIA projections were correct, almost 30 GW of capacity was retired due to MATS.

This included the Corette plant in Billings, which was permanently closed in August 2015. A more recent development has been the rollout of carbon emission regulations. In Massachusetts v. EPA the U.S. Supreme Court determined “that greenhouse gases, including carbon dioxides, are air pollutants under the Clean Air Act and EPA must determine if they threaten public health and welfare.”

On December 15, 2008, the EPA found that current and projected concentrations of greenhouse gases endangered the public health and welfare of current and future generations. In August 2015 the EPA published its final rule on reducing greenhouse gas (GHG) emissions from electric generating units. These require states to file carbon reduction plans by 2016 and to meet their first targets for reduction by 2022.

Due to a number of substantial revisions that occurred in the time interval that elapsed since the preliminary rules were first published in June 2014, the emissions reduction targets for individual states with heavier dependence on coal production and coal-fired electricity generation were raised considerably.

The implications for the coal industry are stark. An analysis of the old emission targets embodied in the preliminary rules conducted by the EIA predicted that coal-fired electric energy generation would be lower by 600,000 gigawatt-hours in year 2025. This would be a 40 percent reduction from the output of coal electric generating units today.

As drastic as this sounds, the analysis of the new rule’s effect, when it is completed, will doubtless be even larger. Yet with the announcement of the final rules as part of the EPA’s Clean Power Plan comes a new and unwelcome facet of regulatory policy – uncertainty. The prospect for a reversal of the EPA rule, either through court challenge, presidential elections or the legislative process, cannot be discounted.

The MATS rules affecting mercury emissions remain in litigation, remanded to a lower court to address recent challenge to its legality. While this outcome is probably too late in the game to affect shutdown and investment decisions made to comply with MATS, it plants seeds of doubt in the finality of the CPP.

Federal Land Use Challenges

Given these challenges, this would seem to be an inopportune time to revisit the issue of the appropriate royalty rate that the federal government charges companies who extract coal from federally owned land. Opening this question introduces another element of policy uncertainty to a business that furnishes the fuel that still provides more electric energy than any other, and an industry that makes a significant economic contribution to states and regions across the country.

Yet opening this question is precisely what appears to be happening. The U.S. Department of the Interior’s Bureau of Land Management (BLM) conducted “listening sessions” in selected western states as well as in Washington, D.C., to “seek information about how the BLM can best carry out its responsibility to ensure that American taxpayers receive a fair return on the coal resources managed by the federal government on their behalf.”

The likely geographic impact of a near doubling in the effective royalty rates on coal – such as the one set forth in an analysis by Headwaters Institute published in January 2015 – would fall overwhelmingly on “The implications of the EPA’s ruling on reducing greenhouse gas emissions are stark.”

These kinds of changes would likely impact the tax, employment and income benefits that are enjoyed by Western states, including Montana.

The Decade Ahead

Coal has been a significant part of our energy portfolio for over a century, and after enduring a series of setbacks for the first half of this decade, its fortunes could yet swing upward again.

The appetite for electricity in the developing economies in Asia, coupled with a return to the price volatility that has always characterized its competitor fuel, natural gas, could be part of that optimistic scenario.

Confidence in that rosy scenario – from the point of view of producers – is hard to find. The collapsing stock prices of coal companies, the decline in market share, and the prospect of significant regulatory challenges ahead do not bode well for growth in the industry’s future. If setbacks in the industry were to extend to Powder River Basin producers in Montana and especially Wyoming - who are among the most efficient in the world - then it would impact an important economic driver to our state’s economy.

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