Cloud Peak Can Wait Out the Lows

We think the renewal of Cloud Peak's self-bonding is evidence of its best-in-class financial health among its coal peers. As competitors face questions on self-bonding abilities and general liquidity, Cloud Peak's relatively lower leverage gives the company the time to wait for coal markets to improve as bankruptcy questions linger over its peers. At current natural gas prices of roughly $2.80 per thousand cubic feet, Powder River Basin coal's cost advantage remains threatened. However, we continue to believe that as natural gas approaches our energy team's forecast of $4 per mcf, Powder River Basin coal will regain a cost advantage throughout much of its footprint, leading to higher levels of coal burn.

Attractive, Low-Cost Assets Cloud Peak is one of the lowest-cost players in the lowest-cost coal-mining region in the world: the Powder River Basin in southeast Montana and northeast Wyoming. We think PRB coal will increase in price over the next few years since it is a competitive option to natural gas for generating electricity when natural gas prices are above $2.50-$2.75 per mmBtu. With natural gas prices increasing from 2012 lows, demand for PRB coal has improved. Furthermore, with the operating costs of PRB operators lying well below current PRB prices, Cloud Peak can generate growing margins.

Cloud Peak operates three surface coal mines in the PRB (Antelope, Cordero Rojo, and Spring Creek), with production capacity of approximately 90 million-100 million tons annually. From a cost perspective, the PRB is one of the world's most advantageous coal-mining regions, as its thick, uniform coal beds allow miners to use massive trucks and draglines for easy and efficient access and transport. While shipping costs for PRB coal can be more than 2-3 times the extraction cost on a per-ton basis, the majority of the U.S. coal power plants still find it more economical to burn PRB coal than other types of coal, given PRB coal's abundance, minimal sulfur content, and ultralow production costs. Furthermore, while Central Appalachian coal miners' costs continue to balloon as a result of geology, regulation, and safety issues, threatening the long-term viability of CAPP coal use, PRB coal costs are expected to grow at a much more moderate pace.

In addition to its attractive low-cost coal assets in the PRB, we like Cloud Peak's keen focus on cost control. By entering into many of its delivery contracts two to three years in advance, the company optimizes its near-term cost structure to match its contracts, partly reducing the impact of volatile domestic coal prices. This approach allows Cloud Peak to enjoy the lowest production costs in the PRB.

Powder River Basin Makes a Moat We believe Cloud Peak enjoys a narrow economic moat, primarily because of its large, established position in the low-cost Powder River Basin in the United States. We're big fans of the company's PRB operations, where Cloud Peak is the third largest of four miners that control the basin; the others are Peabody Energy BTU, Arch Coal ACI, and Alpha Natural Resources ANR. Compared with other U.S. coal basins (and across the world), cash extraction costs are extremely low, at well under $10 per ton, excluding cash royalty payments. This cost advantage has allowed the basin to grow quickly over the past three decades and steadily take share from the other U.S. production centers, especially Central Appalachia.

In general, PRB producers have shown production restraint in the face of weak demand in the past (such as during the downturn in coal prices during 2009 and 2012), which is supportive of healthy profit margins for the existing PRB operators, including Cloud Peak. Furthermore, we believe existing large PRB operators such as Cloud Peak are relatively protected from new entrants, given the sizable infrastructure investments they have already made in the basin, which allow them to mine adjacent coal deposits using much lower incremental capital than a new miner without any existing operations in the basin could. Furthermore, the relative proximity of the mines in the basin allows existing operators to shift resources among existing mines.

Historically, coal has been a subject of environmental regulatory scrutiny. Two of the most potentially impactful regulations for coal demand are New Source Performance Standards and the Mercury and Air Toxics Standards. The Environmental Protection Agency proposed NSPS to set new carbon dioxide emission standards for new coal-fired and natural gas-fired power plants. If enacted, this would limit new coal-fired units to 1,000 pounds of carbon dioxide per megawatt-hour, effectively banning construction of new units without the use of carbon capture and storage technology, which remains uneconomical at this time. Although no discussion has taken place on NSPS' application to existing units, the EPA is only expected to propose standards after finalizing NSPS for new units. After the initial proposal in April 2012, the EPA allowed a 12-month comment period in which it received about 2.6 million comments. Originally intended to be finalized by April 2013, NSPS remains in development and it could be years until implementation, given the amount of comments, potential changes, and likely lawsuits. Ultimately, although NSPS' impact on current coal demand would be minimal, it makes any expansion of coal-burning capacity virtually impossible. This limits growth opportunities for coal to increased utilization of current capacity and cross-basin market share stealing.

Separately in 2012, the EPA finalized MATS, which installs maximum achievable control technology standards on hazardous air emissions including mercury, particulate matter, sulfur dioxide acid gases, and other certain metals for both new and existing coal-fired power plants. The EPA set the standards based on the reductions of the best-performing comparable source for new sources and based on the top 12% best-controlled sources for existing sources. Plants had until Jan. 1, 2015, for implementation (three years after finalization, with a possible extension to Jan. 1, 2016, granted by state permitting authorities on a unit-by-unit basis). MATS could have an adverse impact on nearly 60-70 gigawatts of coal-fired capacity, but would probably be limited to older, less efficient plants in the Eastern U.S. In general, any regulation including MATS could have a negative impact on coal demand given the additional compliance requirements. However, as coal-fired power plants comply, sulfur amounts--the advantage that originally led to the rise in PRB coal--could become even less of a factor in deciding among basins. Ultimately, this could lead to increased demand for lower-cost PRB and Illinois Basin coal at the expense of high-cost Appalachian coal. Furthermore, as Eastern U.S. plants (the predominant customers of Appalachian coal) would be the most likely affected, demand for Appalachian coal is the most likely to suffer.

Expect PRB-CAPP Cost Differential to Widen The PRB is characterized by extremely thick and cheap-to-mine deposits. This inherent geologically based cost advantage is improving steadily as coal becomes more difficult to extract from the Eastern U.S. basins, such as Central Appalachia. The extremely low cost of PRB coal has allowed it to take market share from other coal-producing regions, particularly Central Appalachia, and we believe this cost differential will continue to widen. Central Appalachia is exposed to geological issues as miners chase dwindling coal reserves deeper underground and more stringent safety regulations escalate the cost inflation facing Appalachian coal miners. In contrast, the PRB faces a much more stable cost environment with very large-scale operations, an exceptional safety record, and coal deposits lying close to the surface. PRB coal miners such as Cloud Peak will experience some cost inflation, especially as most PRB coal beds dip down to the west at an angle of two to three degrees, meaning that strip ratios will increase as PRB coal miners chase the coal beds westward. However, we think PRB coal extraction costs will increase at a much slower rate than in the Appalachian coal basins.

Although we believe the cost differential will widen between CAPP and PRB coal production, we believe this differential is offset by plants' limited ability to switch between coal types. As CAPP is bituminous and PRB is subbituminous, plant specifics such as boiler size and shape are not ideally suited for switching between the two coal types, resulting in a loss in efficiency. Historically, switching could be achieved with the opening of new plants optimized for PRB coal and the retiring of plants optimized for CAPP coal. Currently, potential regulations such as NSPS are effectively barring utilities from this option. On the other hand, plants can make adjustments to exiting CAPP-optimized plants to minimize lost efficiency, but these changes are expensive and time-consuming. Until we see utilities executing these adjustments and have a better idea for the costs involved, we do not think the growing cost differential between CAPP and PRB will necessarily translate into a realizable advantage at this time. Furthermore, the potential for regulatory action that may limit all coal's attractiveness may overshadow any gain PRB will make through the widening cost differential.

Cyclical Industry, but Solid Financial Health Coal mining is a highly cyclical industry, and producers have high fixed costs. Poor economic growth or unfavorable weather patterns (such as a warm winter or a cool summer) would reduce domestic coal demand and prices. In the PRB, the government and railroads extract large amounts of rent from the coal producers, and higher government lease rates for coal reserves in particular could lead to significant cost inflation for PRB operators such as Cloud Peak. Furthermore, low natural gas prices and more stringent environmental regulations on power plants are factors that would encourage utilities to switch from coal to gas in generating electricity, which in turn would crimp domestic coal demand. On the other hand, periods of strong demand and supply disruptions can result in exorbitant profits for coal miners. Despite its low-cost position, relatively strong financial health, and lack of exposure to metallurgical coal, Cloud Peak still faces a meaningful amount of risk that can significantly affect its business.

Cloud Peak exhibits good financial health, particularly among its coal mining peers. Leverage remains well controlled, with net debt/last-12-months EBITDA roughly below 2 times and interest coverage around 3 times. These leverage characteristics help position the company to absorb any further softness in the coal markets. We expect Cloud Peak to generate sufficient cash flow to support capital spending requirements and therefore reduce its need for additional incremental borrowing. Unlike many of its peers, Cloud Peak does not carry outstanding retirement or pension obligations, which add to other industry participants' total debt burden. It also maintains adequate liquidity, with roughly $170 million of cash and an available undrawn bank facility of $500 million.

Cloud Peak's debt consists of two outstanding bond issues: $300 million senior notes due 2019 that are currently callable and $200 million senior unsecured notes due 2024. We expect management to consider refinancing the $300 million senior notes when they reach their call option dates in an effort to lower overall interest costs and improve interest coverage levels, as it did with the previously outstanding $300 million senior notes due 2017 that were callable in December 2013. We believe the company can refinance these notes at lower levels, as the recently issued notes' coupon is 6.375%, or roughly 2 percentage points lower than the retired notes.