The current coal bust might lead to a future boom.
Gary L. Hunt is president of the advisors business unit of Ventyx Energy Group and can be reached at firstname.lastname@example.org. Hans Daniels is director, coal advisory services at Ventyx Energy Group and can be reached at email@example.com. Note: Global Energy Decisions and New Energy Associates were both acquired by Vista Equity Partners, a private equity fund, in 2007, and rolled up along with Indus International and Mobile Data Solutions Inc. into a new company called VENTYX. Together Global Energy and New Energy Associates comprise the Ventyx Energy Group
Coal is taking a beating. As mining costs rise, coal reserves deplete, emission regulations strengthen, and inter-fuel competitive dynamics change, the allocation of coal in the electric generation industry is certain to see substantial changes. The uncertainties over CO2 regulations and emissions standards are having a chilling impact on both proposed and current coal investment.
For example, under foreseeable prices for CO2 credits ($20 and $40 a ton), mid-sized (200 MW), less efficient (11,280 Btu/kWh heat rate) coal plants lose most of their revenues (see Figure 1). This hurts contracted assets too, because some of the older contracts either do not have any terms to cover these new emission costs or have vague language that will trigger long negotiations.
At the same time, uncertainties over CO2 regulation and higher construction costs are driving coal plant cancellations. Total cancellations among such projects have reached 45,000 MW, and 15,000 MW more have been postponed (see Figure 2). During the first half of 2007, out of 22,000 MW of new projects cancelled, 15,000 MW was coal capacity.
Despite these current anxieties over coal, it is too early to count coal out. In fact, the long-term fundamental analysis suggests coal will continue playing a pivotal role in the U.S. power generation sector for years to come (see Figure 3). Overall power generation load growth is expected to increase by 1.5 percent each year, consistent with long-term trends. While natural gas is expected to account for more than half of the incremental growth in power generation, healthy competition for baseload will occur between IGCC clean coal and new nuclear.
Since 1959, the U.S. electric power generation sector has consumed more coal than any other sector. It has shown significant demand growth and increased its coal demand share from 73 percent in 1975 to 93 percent of total U.S. coal consumption in 2006, a year in which total electric power coal consumption was more than 1 billion tons. The steady increase in coal consumption by the electric generation sector shows coal’s reliability as a fuel source despite any perceived competitive disadvantages it may have.
In order to meet increasing demand, the U.S. coal-mining industry has increased its production by about 52 million tons in the past 10 years, to a total of 1.16 billion tons. During this period, the Powder River Basin (PRB) increased production by 55 percent, to 472 million tons in 2006 from 1997 levels. In the same time frame, Central Appalachia has seen production decline by 18.6 percent to 236 million tons in 2006. Production of higher-sulfur Illinois Basin coal has declined 13.4 percent to 96 million tons in response to the Clean Air Act amendments, while Northern Appalachia coal production has declined 12.5 percent to 136 million tons since 1997, primarily for the same reason. The only basin to see an increase in production since 1997 is the Rocky Mountain Basin, showing a modest increase of 1.3 percent in the last 10 years with 112 million tons of total production in 2006. Coal imports steadily have increased from 15 million tons in 2000 to 36 million tons in 2006, a 142 percent increase.
All major coal producing basins have seen declines in basin-level productivity since 2001, due to deteriorating reserve quality and slowing improvement of mining technology and scale economies. The PRB has seen its overall basin-level productivity decline by 16.7 percent, to 34.98 tons per miner-hour since 2001. In the same time frame, Central Appalachia has seen productivity decline by 25 percent, to 2.82 tons per miner-hour in 2006. Illinois Basin and Rocky Mountain productivity also have seen very significant declines of 11.26 and 20.34 percent, respectively. Northern Appalachia productivity saw a decrease of only 1.23 percent, the smallest productivity decline of all the major basins since 2001.
Coal prices have increased in all basins over the last 10 years. The weighted average “free on board” (FOB) mine prices (spot and contract) have increased 32 percent in the United States from 1998 to 2006. Central Appalachia has seen the most significant increase in FOB prices— from $25 to $46 a ton over this time period, an increase of 84 percent. The Illinois Basin and Northern Appalachia have both seen a 36 percent increase in FOB mine prices, with 2006 prices of $29.92 and $37.39 a ton, respectively. Rocky Mountain coal has realized a modest increase on a dollar-per-ton basis of approximately five dollars, though this does equate to a significant 27 percent increase. The PRB’s increases in FOB mine prices have been the most modest— from $7.83 to $9.11 a ton, or 16 percent.
In 2006, coal-fired power plants generated 50 percent of U.S. electricity. A decade ago the picture was very different. Coal’s share of electricity generation was near 60 percent in 1997, but has since fallen to 50 percent due to a massive build out of cheap (approximately $600 a kW) natural gas plants, driven by very low natural gas prices in the late 1990s and early 2000s. With low gas prices apparently a thing of the past, coal solidly holds the title of lowest-cost fossil fuel for electricity generation. This is reflected in plant utilization rates, which are much higher for coal than for gas. In 2006, the utilization rate, or capacity factor, of coal plants was 71 percent compared to 25 percent for gas plants. Despite the fact that coal’s generation share has diminished during the last 10 years, coal production and consumption increased during that time frame as demand for coal as a source for power generation increased to meet bourgeoning demand for electricity in the United States.
Transportation costs factor strongly in the ultimate delivered price at the plant. For instance, 60 percent of the delivered price of coal produced in the PRB is attributable to transportation costs, on average. Rail is the transportation method most heavily relied upon in the coal industry due to the vast geographic area that rail infrastructure covers and its ability to move large amounts of coal long distances through varied terrain. Almost 72 percent of coal deliveries use rail transportation for at least a portion of their journey. Rail capacity issues are particularly important for PRB coal, where the average haul distance is 1,200 miles to the plant and 2,400 miles roundtrip—almost exclusively by rail. Union Pacific (UP) and Burlington Northern Santa Fe (BNSF), the only railroads serving the PRB, are investing in capacity expansion, and another railroad might construct a line into the PRB.
River barges offer one of the most economical ways to move coal large distances on a cost per ton-mile basis. The obvious constraint to moving coal via barge is geographic location of coal mines and plants in relation to navigable waterways and access to river docks. In 2006, 161 million tons of coal had terminating transportation on river barges. Lake vessels are more constrained by geographic location of plants than river barges and were responsible for only 25 million tons of delivered coal in 2006. Fifty percent of the Illinois Basin’s and Central Appalachia’s deliveries, amounting to nearly 130 million tons, utilized trucks as their first, and in some cases only, form of transportation in 2006. Ocean vessels account also for some of the nearly 81 million tons of combined U.S. imports and exports.
Historically coal was sold under contracts that specified longer terms than they do today. The tendency in the industry has been to shorten contract length as other, potentially more reliable means of managing risk (e.g., over-the-counter coal trading) have become more widely available and accepted. The reality is that over 85 percent of coal is delivered under contracts with lengths of one year or more. This dynamic is unlikely to change anytime soon because of the risk-management tool it provides to both producers and consumers.
Deeper and thinner seams, growing underground mine-safety costs, diminishing opportunities to consolidate reserves, falling productivity, and rising mining input costs (e.g., labor, fuel, explosives, etc.) will cause production to decrease and increase mining costs in Central Appalachia. Trends in Central Appalachian coal production over the last 10 years are towards surface mining and away from underground mining in order to contend with cost issues associated with underground mining. With mountaintop mining under attack in the courts from environmentalists, there is an added degree of uncertainty about the future of some operations. Opportunities for companies to capitalize on potential synergies and the pressure from low prices and rising costs—with some producers particularly exposed—provide room for ongoing consolidation of operations, especially in Central Appalachia.
In addition to cost pressures, coal faces challenges on the demand side in the form of environmental regulation of power plants and competition from other sources of electric power. Coal remains far cheaper than natural gas on a delivered basis, even with current environmental costs factored in. Alternatives to coal-fired power each come with a set of advantages and disadvantages.
There are 104 operating nuclear units in the U.S. today, which account for 21 percent of U.S. electric power generation. Utilization is high at 90 percent, which means that nuclear power will not increase its market share without new plant construction. Nuclear fuel is currently cheap but prices are expected to increase (see “Nuclear Fuel Future,” p.26), and waste disposal is an ongoing and long-term expense. Efforts to add capacity with new plants face long lead times and public opposition, but several are making progress (see “Financing New Nukes”).
Gas-fired capacity is the largest of any other single U.S. power source, at 475 GW. New plant construction surged in the late 1990s and early 2000s in response to the promise of low gas prices, inexpensive plant construction costs, and increasing government and public scrutiny regarding emissions in recent years. Despite plant utilization of just under 20 percent, natural gas-fired plants contribute 20 percent to total U.S. generation. High fuel costs and volatility likely will keep utilization levels low, but another 60 GW are on the drawing board nonetheless.
Hydropower’s percentage of electrical output has ranged from 11 percent to 7 percent over the past 10 years, much of which is attributable to fluctuations in regional precipitation levels. There is an increasing awareness of some of the negative environmental impacts associated with dams (e.g., ecosystem alteration, fish migration interference, etc.). Several regions are in the midst of droughts that are lowering output and new, large scale capacity additions are virtually out of the question in the United States.
Renewable energy’s contribution to electricity output is barely 2 percent and remains relatively insignificant. In 2006, wind accounted for 0.61 percent of all electric production in the United States. Wind’s contribution will grow as long as subsidies last, but output intermittency and transmission remain sizeable obstacles (see “Taming the Wind”). Renewable portfolio standards and carbon regulation will lend support for greater deployment.
Since 1990, net SO2 and NOx emissions at coal burning plants have fallen by 31.3 percent and 33.1 percent, respectively, while the amount of coal burned has increased from 783 million tons a year to 1,015 million tons a year. Nonetheless, utilities continue facing close scrutiny to reduce their emission exposure, which has helped contribute to coal’s decreasing role in U.S. electricity supply—displaced primarily by gas. Investments in emissions-control systems have resulted in 121 GW of coal-fired capacity that currently has SO2 controls and 306 GW with some form of NOx controls. New emissions limits under the Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule (CAMR) have spurred a further boom in emissions control equipment installations.
Boom and Bust
Coal markets are subject to boom-and-bust cycles with supply and demand constantly in flux and production, contracts, transportation, and stockpiles all contributing to the complex interrelationships of the markets. To address this uncertainty, Ventyx Energy Group uses the Coal Quality Market Model (CQMM) to forecast future U.S. consumption, allocation, and price of coal from every mine to every boiler over the 25-year study period. The CQMM relies on input data from the Velocity Suite, the industry’s leading coal and energy market database, along with the help of numerous government, public, and private data sources.
Coal will remain the single largest contributor to overall U.S. electricity supply over the course of this forecast. Coal generation will increase almost 28 percent through 2031, although coal’s relative share of the market will decline by four percentage points. Gas-fired capacity will increase its market share of generation by 10 percentage points while posting a 227-percent increase in actual electricity production; this is the second largest growth in generation in this forecast. The largest relative growth in generation comes from non-hydro renewables, which will experience a 341 percent increase, but still remain only 5 percent of the total U.S. generation.
U.S. coal demand differs among the different regions of the country due to several key factors. These include growth in overall electricity demand; status of the existing coal fleet, including the age of the units and their utilization rate; difficulty in permitting new plants; and, delivered cost of coal and competing fuels.
The Northeast region has the lowest current coal demand and the slightest increase in coal demand of all the regions over the forecast period. With an average growth of 0.5 percent a year, its total demand will increase 13 percent over the 25-year time span. The West region will remain also relatively flat, increasing 16 percent over 25 years. The Southeast region is expected to increase 24 percent, which equates to over 160,000 GWh of coal generation. The Midwest shows growth every year resulting in the highest absolute increase (248,300 GWh or 34 percent since 2007) in coal power demand by 2031. The South Central region, while small, shows the greatest average yearly increase (1.5 percent) and overall increase (44 percent) in coal-fired electricity generation.
Total deliveries of coal within the United States are expected to increase from 1.05 billion tons in 2007 to 1.3 billion tons in 2031, an annual average increase of 1.98 percent. Production of coal is expected to increase for all basins except for Central and Southern Appalachia, which should see production decrease by 45 percent and 28 percent, respectively. The largest percentage increase in demand is expected to come from Colombian coal at 178 percent—a 36 million ton increase over the 25-year study period. Demand for PRB coal is forecasted to rise by 50 percent (average annual growth of 9.4 million tons a year) and the Illinois Basin should see a 37 percent growth in demand (average annual growth of 1.28 million tons/year). Rocky Mountain coal is expected to command a 27 percent increase in demand (annual growth of 1.1 million tons/year). Lignite demand should remain relatively flat.
Fully allocated mine costs, which include full production costs including return on capital, are expected to increase over the forecasted period. The cash cost of coal for all U.S coal basins is expected to rise for a number of reasons, including: decreasing productivity due to thinner and deeper seams; limits on economies of scale; rising prices for fuel, equipment, tires, and explosives; competition for skilled labor across the energy sector; and an aging workforce that is nearing retirement in the East.
U.S. coal mine fully allocated costs are expected to decrease over the next five years by about 4 percent. This is a result of increases in production of PRB coal and decreases in production of Central Appalachian coal. Numerous industry sources have indicated that the MINER Act will add up to $8 per ton of coal extracted from underground mines due to increased safety costs, higher penalties, and more frequent stoppages.
At Western coal basins (including the Powder River and Rocky Mountain), fully allocated costs are expected to increase by about 5 to 6 percent over the next five years. Factors contributing to that change include: increasing coal ratios; seam splitting and washouts; higher input costs; and increasing tax and royalty costs. These cost increases are not expected to be offset by productivity-increasing technological improvements.
Productivity is the single largest factor that contributes to a mine’s overall production costs. Aggregate productivity at U.S. coal mines is likely to fluctuate through the mid-term. The variability in productivity is mainly due to large volumes of higher cost, lower productivity mines being shut-in, and some larger western mines ramping up production as market conditions and prices fluctuate. For example, in 2007 over 43 million tons of production capacity with productivity less than 19.6 tons per miner-hour will go off line. With reserve blocks becoming increasingly difficult to mine, major increases in productivity in the future are unlikely unless new technologies for extracting coal are developed.
Eastern U.S. productivity (Appalachia and Illinois Basin) primarily depends on the mine type (surface vs. underground) and technology (e.g., continuous miner vs. longwall). Surface mines typically have higher productivity than underground mines due to accessibility and economies of scale that allow for easier and more cost-effective production. On average, eastern surface mines have almost twice the productivity as underground mines.
Central Appalachian productivity will decline by a total of 6 percent over the next five years as producers continue to move into thinner and more geologically challenging seams. Northern Appalachian productivity will not decline as rapidly as Central Appalachia, with only a 2.5 percent drop over the next five years. While some underground seams in this region are becoming smaller, the extensive use of longwall miners in Northern Appalachia helps support positive productivity. Even though Illinois Basin production capacity will grow over the mid term, productivity is expected to decline through 2010. Productivity in the PRB is expected to flatten over the next three years, but remain the highest of all the U.S. coal basins.
Coal Price Forecast
FOB mine prices likely will escalate over the next 25 years due to increasing production costs coupled with growing demand. Unparalleled mining conditions allow the PRB to have much lower FOB mine prices than other areas with smaller, less productive mines. Short-term FOB prices for South American imports will rise due to increased Atlantic Basin demand for the coal, coupled with a weak U.S. dollar. At the same time, expanded supply with weakened European demand will dampen import coal prices through the long term. Northern Appalachian FOB prices should experience the strongest growth over the mid term due to robust demand. FOB coal price inflation will be tempered by escalating competition among the basins for customers that have the ability to switch to a primarily Btu-centric rather than sulfur-centric coal product.
Of all the transportation issues facing the U.S. coal markets, expansion of existing rail and development of new rail in the PRB will have the biggest impact on U.S. coal consumption patterns. In addition to plans by UP and BNSF to expand the existing lines, there are two major plans to add more transportation capacity out of the PRB: the Dakota, Minnesota & Eastern Railroad and development of the Tongue River Railroad. Increased competition for tonnage from the PRB could be the only check on the two major rail carriers’ stranglehold on Western rail pricing, which likely will show the greatest increases over the forecast period—nearly 30 percent, compared to about 15 percent for Eastern rail.
Besides western rail pricing and bottlenecks, forecasted coal transportation will be dependent upon a wide variety of factors. Barge pricing likely will remain flat in constant dollars over the 25-year period, with volatility over the short- and mid-term. Lake vessels also will show little pricing inflation, although environmental concerns coupled with climate change related freezing/thawing patterns could add uncertainty. And current extremely high prices of ocean vessels should settle down with increased availability and port expansions on the way.
Increased FOB mine and transportation prices will translate into continued pressure on the delivered price of coal. While the PRB has low FOB mine prices, the coal produced is transported great distances and in great quantities because of its low heat content. Eastern regions (Southeast and Northeast) have high delivered coal costs because of higher Eastern mining costs or very high transportation rates for cheaper western coal. Colombian imports also keep Eastern prices high due to high transportation costs. For Western coal consumers, lower prices and short hauls equates to retaining the lowest burner-tip price of coal, even with considerable inflation over the forecast period (see Figure 4).
While the North American coal industry is experiencing anxiety attacks today, mostly over the uncertainty of CO2 emission reduction requirements and the rising costs of new plant construction, the long-term prospects for coal remain solid based upon fundamentals.