Item 1. Business.
Overview
Cloud Peak Energy Inc. is the third largest producer of coal in the U.S. and in the Powder River Basin, or PRB, based on our 2010 coal production of 95.3 million tons. We had revenues from our continuing operations of $1.4 billion in 2010. We operate some of the safest mines in the industry. According to Mine Safety and Health Administration, or MSHA, data, in 2010 we had one of the lowest employee all injury incident rate among the ten largest U.S. coal producing companies. We operate solely in the PRB, the lowest cost coal producing region of the major coal producing regions in the U.S., and operate two of the four largest coal mines in the region and in the U.S. Our operations include three wholly-owned surface coal mines, two of which are in Wyoming and one of which is in Montana. We also own a 50% interest in a fourth surface coal mine in Montana. We produce sub-bituminous steam coal with low sulfur content and sell our coal primarily to domestic electric utilities, supplying approximately 47 customers with over 108 domestic plants. We do not produce any metallurgical coal. Steam coal is primarily consumed by electric utilities and industrial consumers as fuel for electricity generation. In 2010, the coal we produced generated approximately 4% of the electricity produced in the U.S. As of December 31, 2010, we controlled approximately 970 million tons of proven and probable reserves.
Cloud Peak Energy Inc., a Delaware corporation organized on July 31, 2008, is a holding company that manages its wholly-owned consolidated subsidiary CPE Resources, but has no business operations or material assets other than its ownership interest as of December 31, 2010 of 100% of the common membership units in CPE Resources as discussed more fully in "History" below. Our only source of cash flow from operations will be distributions from CPE Resources pursuant to the CPE Resources limited liability company agreement. We also receive management fees pursuant to a management services agreement between us and CPE Resources as reimbursement of certain administrative expenses.
History
Our business operations are conducted by CPE Resources, formerly known as Rio Tinto Sage LLC, a Delaware limited liability company formed as a wholly-owned subsidiary of RTEA on August 19, 2008. RTEA is our predecessor for accounting purposes. RTEA, a Delaware corporation, formerly known as Kennecott Coal Company, was formed as a wholly-owned subsidiary of Rio Tinto America on March 1, 1993. Between 1993 and 1998, RTEA acquired the Antelope, Colowyo, Jacobs Ranch and Spring Creek coal mines and the Cordero and Caballo Rojo coal mines, which are operated together as the Cordero Rojo coal mine, and a 50% interest in the Decker coal mine, which is operated by a third-party mine operator. In December 2008, RTEA contributed Rio Tinto America's western U.S. coal business to CPE Resources (other than the Colowyo mine, which is now owned indirectly by Rio Tinto America). On October 1, 2009, CPE Resources sold the Jacobs Ranch mine to Arch Coal, Inc. and distributed the proceeds to Rio Tinto. On November 19, 2009, Cloud Peak Energy Inc. acquired from RTEA approximately 51.0% of the common membership units in CPE Resources in exchange for a promissory note and the SEC declared effective Cloud Peak Energy Inc.'s Registration Statement on Form S-1 (File No. 333-161293) for its initial public offering, or IPO. As a result of these transactions, Cloud Peak Energy Inc. became the sole managing member of CPE Resources with a controlling interest in CPE Resources and its subsidiaries. Cloud Peak Energy Inc. used the proceeds from the IPO to repay the promissory note upon the completion of the IPO on November 25, 2009.
On December 15, 2010, Cloud Peak Energy Inc. priced a secondary offering of 29,400,000 shares of its common stock on behalf of Rio Tinto (the "Secondary Offering"). In connection with the
Secondary Offering, we exchanged 29,400,000 shares of common stock for the common membership units of CPE Resources held by Rio Tinto and completed the Secondary Offering, resulting in a divestiture of 100% of Rio Tinto's holdings in CPE Resources. As a result of this transaction, CPE Resources is now a wholly-owned subsidiary of Cloud Peak Energy Inc.
The following condensed diagram depicts our organizational structure as of December 31, 2010:
(1)Operated together as the Cordero Rojo mine. Coal Characteristics
In general, coal of all geological compositions is characterized by end use. Heat value and sulfur content are the most important variables in the profitable marketing and transportation of steam coal. We mine, process and market low sulfur content, sub-bituminous steam coal, the characteristics of which are described below. Because we operate only in the PRB, which does not have metallurgical coal, we produce only steam coal.
Heat Value
The heat value of coal is commonly measured in British thermal units, or "Btus." Sub-bituminous coal from the PRB has a typical heat value that ranges from 8,000 to 9,500 Btus. Sub-bituminous coal from the PRB is used primarily by electric utilities and by some industrial customers for steam generation. Coal found in other regions in the U.S., including the eastern and midwestern regions, tends to have a higher heat value than coal found in the PRB.
Sulfur Content
Federal and state environmental regulations, including regulations that limit the amount of sulfur dioxide that may be emitted as a result of combustion, have affected and may continue to affect the demand for certain types of coal. The sulfur content of coal can vary from seam to seam and within a single seam. The chemical composition and concentration of sulfur in coal affects the amount of sulfur dioxide produced in combustion. Coal-fired power plants can comply with sulfur dioxide emissions regulations by burning coal with low sulfur content, blending coals with various sulfur contents, purchasing emission allowances on the open market and/or using sulfur-reduction technology. PRB coal typically has a lower sulfur content than eastern U.S. coal and generally emits no greater than 0.8 pounds of sulfur dioxide per million Btus. All of our reserves are compliance coal under the Clean Air Act.
Higher sulfur noncompliance coal can be burned in plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions by up to 90%, and in facilities that blend compliance and noncompliance coal. In 2009, out of utilities with a coal generating capacity of approximately 314 GW, utilities accounting for a capacity of over 168 GW had been retrofitted with scrubbers. Furthermore, all new coal-fired generation plants built in the U.S. are expected to use some type of sulfur-reduction technology. The demand or price for lower sulfur coal may decrease with widespread implementation of sulfur-reduction technology.
Other
Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from seam to seam. Ash content is an important characteristic of coal because it impacts boiler performance and electric generating plants must handle and dispose of ash following combustion. The ash content of PRB coals is generally low, representing approximately 5% to 10% by weight. The composition of the ash, including the proportion of sodium oxide, as well as the ash and fusion temperatures are important characteristics of coal and help determine the suitability of the coal to end users. In limited cases, customer requirements at the Spring Creek mine have required, and may continue to require, the addition of earthen materials to dilute the sodium oxide content of the post-combustion ash of the coal.
Moisture content of coal varies by the type of coal and the region where it is mined. In general, high moisture content is associated with lower heat values and generally makes the coal more expensive to transport. Moisture content in coal, on an as-sold basis, can range from approximately 2% to over 35% of the coal's weight. PRB coals have typical moisture content of 25% to 35%.
Trace elements within coal that are of primary concern are mercury, for health and environmental reasons, and chlorine, for utility plant performance. Trace elements of mercury and chlorine in PRB coal are relatively low compared to other coal regions. However, the low chlorine content of PRB coal is associated with the emission of elemental mercury, which is difficult to remove with conventional pollution control devices.
Coal Mining Methods
Surface Mining
All of our mines are surface mining operations utilizing both dragline and truck-and-shovel mining methods. Surface mining is used when coal is found relatively close to the surface. Surface mining typically involves the removal of topsoil, and drilling and blasting the overburden (earth and rock covering the coal) with explosives. The overburden is then removed with draglines, trucks, shovels and dozers. Trucks and shovels then remove the coal. The final step involves replacing the overburden and topsoil after the coal has been excavated, reestablishing vegetation and plant life into the natural habitat and making other changes designed to provide local community benefits. We typically recover 92% or more of the economic coal seam for the mines we operate.
Coal Preparation and Blending
Depending on coal quality and customer requirements, in almost all cases the coal from our mines is crushed and shipped directly from our mines to the customer. Typically, no other preparation is needed for a saleable product. However, depending on the specific quality characteristics of the coal and the needs of the customer, blending different types of coals may be required at the customer's plant. Coals of various sulfur and ash contents can be mixed or "blended" to meet the specific combustion and environmental needs of customers. All of our coal can be blended with coal from other coal producers. Spring Creek's location and the high Btu content of its coal make its coal better suited than our other products for export and transportation to the northeastern U.S. coal markets for blending by the customer with coal sourced from other markets to achieve a suitable overall product.
Mining Operations
We operate solely in the PRB. Two of the mines we operate are located in Wyoming and one is located in Montana. We also own a 50% non-operating interest in the Decker mine, which is located in Montana and operated by a third-party mine operator. We currently own the majority of the equipment utilized in our mining operations, excluding the Decker mine. We employ preventative maintenance and rebuild programs and upgrade our equipment as part of our efforts to ensure that it is productive, well-maintained and cost-competitive. Our maintenance programs also utilize procedures designed to enhance the efficiencies of our operations. The following table provides summary information regarding our mines as of December 31, 2010.
(1)Based on the respective mine's current air quality permit restrictions.
(2)Post-combustion ash from Spring Creek coal contains an average of approximately 8% sodium oxide. Earthen materials can be selectively blended with the coal within the crushing facility to
reduce the post-combustion sodium level and enable the production of a range of products tailored for customers requiring lower sodium levels.
(3)Tons sold numbers reflect our 50% interest in the Decker mine.
(4)The tonnage shown for "Other" represents our purchases from third-party sources that we have resold, including coal we have purchased and resold from the Jacobs Ranch mine, which our predecessor used to own. See "-Customers and Coal Contracts-Broker Sales and Third-Party Sources."
All of our operations utilize dragline and truck-and-shovel mining methods. Our Antelope and Cordero Rojo mines are served by the BNSF and UP railroads. Our Spring Creek mine and the Decker mine are served solely by the BNSF railroad.
The following map shows the locations of our mining operations:
Antelope Mine
The Antelope mine is located in the southern end of the PRB approximately 60 miles south of Gillette, Wyoming. The mine extracts steam coal from the Anderson and Canyon Seams, with up to 44 and 36 feet, respectively, in thickness. We have nominated as an LBA, a large coal tract adjacent to our existing operation. The BLM will determine if the tract will be leased, and if so, the final boundaries of, and the coal tonnage for, this tract. Acquisition of this tract would facilitate access to approximately 80 million tons of non-reserve coal deposits that we control. We currently expect the BLM will schedule this LBA for bid sometime in 2011, subject to the outcome of legal challenges filed in 2010 against the BLM and the Secretary of the Interior by environmental organizations with respect to the EIS and other matters associated with the West Antelope II LBA. Other potential large areas of unleased coal north and west of the mine are available for nomination by us or other mining operations or persons.
Cordero Rojo Mine
The Cordero Rojo mine is located approximately 25 miles south of Gillette, Wyoming. The mine extracts steam coal from the Wyodak Seam, which ranges from approximately 55 to 70 feet in thickness. We have nominated as an LBA a large coal tract adjacent to our existing operation, which we now believe the BLM will schedule for lease in 2011 or 2012. The BLM will determine if the tract will be leased, and if so, the final boundaries of, and the coal tonnage for, this tract. Significant areas of unleased coal are potentially available for nomination by us or other mining operations or persons adjacent to our current operations.
Spring Creek Mine
The Spring Creek mine is located in Montana approximately 35 miles north of Sheridan, Wyoming. The mine extracts steam coal from the Anderson-Dietz Seam, which averages approximately 80 feet in thickness. The location of the mine relative to the Great Lakes is attractive to our customers in the northeast because of lower transportation costs. The location of the Spring Creek mine also provides access to export terminals in the Pacific northwest, providing an advantage relative to other PRB mines. As a result, interest from foreign buyers in coal from our Spring Creek mine continues, and, in 2010, we shipped approximately 3.3 million tons of Spring Creek coal through the Westshore terminal. In June 2010, we entered into a Modified Coal Lease (the "Lease Modification") with the BLM. The Lease Modification modified Coal Lease MTM-069782 (the "Existing Lease") and added approximately 48 million tons of proven and probable reserves to the Existing Lease.
Decker Mine
The Decker mine is located immediately to the southeast of our Spring Creek mine in Montana. We own a non-operating 50% interest in the mine. The Decker mine is a union based operation; however, we do not employ any of the Decker mine employees. A third party operates the Decker mine for us and the other 50% owner and markets the steam coal out of the Decker mine. There are two principal seams at West Decker, Dietz 1 and Dietz 2, with typical thicknesses of 51 and 16 feet, respectively, and three seams at East Decker, Dietz 1 Upper, Dietz 1 Lower and Dietz 2, with typical thicknesses of 27, 17 and 16 feet, respectively. In April 2010, the Decker mine entered into a coal sales contract that will extend production and mine life into 2013. The operator continues to seek commercial market opportunities for additional leased and permitted coal tonnage at the Decker mine.
Customers and Coal Contracts
We focus on building long-term relationships with customers through our reliable performance and commitment to customer service. We supply coal to over 47 electric utilities and over 91% of our sales were to customers with an investment grade credit rating as of December 31, 2010. Furthermore, over 72% of our 2010 sales were to customers with whom we have had relationships for more than 10 years.
Sales and Marketing
We have a team of experienced sales, marketing and customer service individuals. To help develop and maintain the relationships we have with our customers, we have divided the department into three teams:
•Sales and Marketing, which focuses on traditional requests for proposals, constituting the majority of our sales;
•Marketing and Pricing, which provides industry insight, recommends pricing strategies and participates in the spot market; and
•Customer Service, which provides contract and after-sales support to our customers.
As of December 31, 2010, we had 17 employees in our sales and marketing department.
Customers
Our primary customers are domestic utility companies with over 108 plants primarily located in the mid-west and south central U.S. Our coal supplies fueled approximately 4% of the electricity generated in the U.S. in 2010. During 2010, approximately 49% of our revenues were derived from our top ten customers. No customer accounted for 10% or more of our revenues in 2010. The following map shows the percentage of our shipped tons of coal by state of destination during 2010 from coal produced at the three mines we own and operate. We also exported approximately 4% of the tons produced at these mines in 2010.
Long-term Coal Sales Agreements
As is customary in the coal industry, we generally enter into fixed price, fixed volume supply contracts of one- to five-year terms with many of our customers. Multiple year contracts usually have specific and possibly different volume and pricing arrangements for each year of the contract. As of December 31, 2010, approximately 64% of our committed tons were associated with contracts that had three years or more remaining on their term. Most of our supply contracts include a fixed price for the term of the agreement or a pre-determined escalation in price for each year. Some of our agreements that extend for a four- or five-year term or longer may include a variable pricing system. These contracts allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales price. For the year ended December 31, 2010, approximately 97% of our revenues were derived from long-term supply contracts with a term of one year or greater. While most of our sales contracts are for terms of one to five years, some are as short as one to six months, and other contracts have terms longer than ten years.
Our coal is primarily sold on a mine-specific basis to utility customers through a request-for-proposal process. The terms of our coal sales agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary by customer,
including base price adjustment features, price re-opener terms, coal quality requirements, quantity parameters, permitted sources of supply, impact of future regulatory changes, extension options, force majeure, termination, assignment and other provisions.
Our supply contracts typically contain provisions to adjust the base price due to new statutes, ordinances or regulations that affect our costs related to performance of the agreement. Additionally, some of our contracts contain provisions that allow for the recovery of costs affected by modifications or changes in the interpretations or application of any applicable statute by local, state or federal government authorities. These provisions only apply to the base price of coal contained in these supply contracts. In some circumstances, a significant adjustment in base price can lead to termination of the contract.
Price re-opener and index provisions, which can be either renegotiated or based on a fixed formula, are present in certain contracts covering future tonnage commitments. These provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may automatically set a new price based on prevailing market price or, in some instances, require us to negotiate a new price, sometimes between a specified range of prices. In some agreements, if the parties do not agree on a new price, either party has an option to terminate the contract. Under some of our contracts, we have the right to match lower prices offered to our customers by other suppliers. In addition, some of our contracts contain clauses that may allow customers to terminate the contract in the event of certain changes in environmental laws and regulations.
Quality and volumes for the coal are stipulated in coal sales agreements. In most cases, the annual pricing and volume obligations are fixed, although, in some cases, the volume specified may vary depending on the quality of the coal. Some customers are allowed to vary the amount of coal taken under the contract. Most of our coal sales agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics, such as heat content, sulfur, ash and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts. Many of our contracts contain clauses that require us and our customers to maintain a certain level of creditworthiness or provide appropriate credit enhancement upon request. The failure to do so can result in a suspension of shipments under the contract.
Our coal sales agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers for the duration of specified events beyond the control of the affected party, including events such as strikes, adverse mining conditions, mine closures or serious transportation problems that affect us or unanticipated plant outages that may affect the buyer. Our contracts generally provide that in the event a force majeure circumstance exceeds a certain time period (e.g., 60-90 days), the unaffected party may have the option to terminate the transaction or transactions under the agreement. Some contracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the buyer.
Agreements between our customers and the railroads servicing our mines may also contain force majeure provisions. Generally, our coal sales agreements allow our customer to suspend performance in the event that the railroad fails to provide its services due to circumstances that would constitute a force majeure.
In some of our contracts, we have a right of substitution, allowing us to provide coal from different mines, including third-party mines, as long as the replacement coal meets quality specifications and will be sold at the same delivered cost.
Generally, under the terms of our coal sales agreements, we agree to indemnify or reimburse our customers for damage to their or their rail carrier's equipment while on our property, other than from
their own negligence, and for damage to our customer's equipment due to non-coal materials being included with our coal before leaving our property.
Broker Sales and Third-Party Sources
From time to time, we purchase coal through brokers to cover any shortfalls under our supply agreements and sell to brokers any excess produced coal.
Our subsidiary, Spring Creek Coal LLC, was a party to a broker sales contract under which it had agreed to sell purchased coal to a wholesale power generation company. In 1978, our Spring Creek subsidiary entered into a long-term coal sales contract to underpin the establishment of the Spring Creek mine. When we acquired the Spring Creek mine in 1993, the contract had been amended to allow the mine to meet its delivery requirements from long-term purchase contracts entered into with two separate mines (one of which was the Jacobs Ranch mine which we subsequently acquired in 1998 and sold in 2009). Due to the nature of the broker sales contract and the market conditions at the time the respective agreements were all executed, our selling price for the coal was higher than our purchasing price. Under this contract, we sold approximately 6.8 million tons per year. This broker sales contract contributed $13.7 million of revenues in 2010. The contract expired following final deliveries under the contract in the first quarter of 2010. See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations-Overview."
For delivery during the year ended December 31, 2010, we purchased 1.7 million tons through brokers and third-party sources.
Transportation
Transportation can be one of the largest components of a purchaser's total cost. Coal used for domestic consumption is generally sold free on board (FOB) at the mine or nearest loading facility, and the purchaser of the coal normally bears the transportation costs and risk of loss in the event of a problem. Most electric generators arrange long-term shipping contracts with rail or barge companies to assure stable delivery costs. Our mines are served by the BNSF and UP railways. In limited circumstances, we sell coal on a delivered basis where we arrange and pay for the freight and charge our customers on a cost plus basis for this service.
Suppliers
Principal supplies used in our business include heavy mobile equipment, petroleum-based fuels, explosives, tires, steel and other raw materials, as well as spare parts and other consumables used in the mining process. We use third-party suppliers for a portion of our equipment rebuilds and repairs, drilling services and construction. We use sole source suppliers for certain parts of our business such as dragline shovel parts and services and tires. We believe adequate substitute suppliers are available. For further discussion of our suppliers, see Item 1A
Item 1A. Risk Factors.
You should carefully consider the risk factors described below and other information contained in this Form 10-K. If any of the following risk factors, as well as other risks and uncertainties that are not currently known to us or that we currently believe are not material, actually occur, our business, financial condition and results of operations could be materially and adversely affected.
Risks Related to Our Business and Industry
Coal prices are subject to change and a substantial or extended decline in prices could materially and adversely affect our revenues and results of operations, as well as the value of our coal reserves.
Our revenues, results of operations and the value of our coal reserves are dependent in large measure upon the prices we receive for our coal. Because coal is a commodity, the prices we receive are set by the marketplace. Prices for coal generally tend to be cyclical, and over the last several years have become more volatile. The contract prices we may receive in the future for coal depend upon numerous factors, including:
•the domestic and foreign supply and demand for coal, including demand for U.S. coal exports from eastern U.S. markets;
•domestic demand for electricity;
•domestic and foreign economic conditions, including economic downturns and the strength of the global and U.S. economies;
•the quantity and quality of coal available from competitors;
•competition for production of electricity from non-coal sources, including the price and availability of alternative fuels, such as natural gas and crude oil, and alternative energy sources, such as nuclear, hydroelectric, wind and solar power, and the effects of technological developments related to these non-coal and alternative energy sources;
•domestic air emission standards for coal-fired power plants, and the ability of coal-fired power plants to meet these standards by installing scrubbers or other means;
•adverse weather, climatic or other natural conditions, including natural disasters;
•legislative, regulatory and judicial developments, environmental regulatory changes, or changes in energy policy and energy conservation measures that would adversely affect the coal industry, such as legislation that limits carbon dioxide emissions or provides for increased funding and incentives for, or mandates the use of, alternative energy sources;
•domestic and foreign governmental regulations and taxes;
•the quantity, quality and pricing of coal available in the resale market;
•the capacity of, cost of, and proximity to, rail transportation facilities and rail transportation delays;
•market price fluctuations for sulfur dioxide emission allowances; and
•subsidies designed to encourage the use of alternative energy sources.
A substantial or extended decline in the prices we receive for our future coal sales contracts due to these or other factors could materially and adversely affect us by decreasing our revenues, thereby materially and adversely affecting our results of operations.
Competition within the coal production industry and with producers of competing energy sources may materially and adversely affect our ability to sell coal at a favorable price.
We compete with numerous other coal producers in various regions of the U.S. for domestic sales. International demand for U.S. coal also affects competition within our industry. The demand for U.S. coal exports depends upon a number of factors, including the overall demand for electricity in foreign markets; currency exchange rates; ocean freight rates; weather disruption; port and shipping capacity; the demand for foreign-produced steel, both in foreign markets and in the U.S. market; general economic conditions in foreign countries; technological developments; and environmental and other governmental regulations. Foreign demand for U.S. coal has increased and decreased over the last decade because of these factors. Decline in foreign demand for U.S. coal could cause competition among coal producers for sales in the U.S. to intensify, potentially resulting in significant additional downward pressure on domestic coal prices, including in the PRB.
In addition to competing with other coal producers, we compete generally with producers of other fuels, such as natural gas and crude oil. A decline in price for natural gas could cause demand for coal to decrease and adversely affect the price of our coal. For example, the average price for natural gas declined from $4.44 per thousand cubic feet as of December 2009 to $4.15 per thousand cubic feet as of December 2010, leading to, in some instances, decreased coal consumption by electricity-generating utilities. If alternative energy sources, such as hydroelectric, wind or solar, become more cost-competitive on an overall basis, demand for coal could decrease and the price of coal could be materially and adversely affected, including in the PRB. Further, legislation requiring the use and dispatch of these alternative energy sources and fuels or legislation providing financing or incentives to encourage continuing technological advances and deployment in this area could further enable alternative energy sources to become more competitive with coal.
Global or U.S. economic and market conditions may have a material adverse affect on our business, financial condition and results of operations.
The recent global economic downturn, particularly with respect to the U.S. economy, coupled with the global financial and credit market disruptions, had an adverse impact on the coal industry generally including our company. For example, the demand for electricity in our target markets decreased during 2009, which led to a decrease in coal consumption by customers. As a result, stockpiles of coal by our customers increased during this time leading to our customers curtailing future orders. In 2009, we also experienced a greater than normal number of customers seeking to reduce the amount of tons taken under existing contracts through contractual remedies, such as force majeure provisions. We cannot predict the timing of such economic disruptions or their long-term impact on domestic and international economies or the magnitude and pace of any recovery. Any actions we may take in response to such economic conditions may be insufficient. A return to the global recession or a recession in the U.S. economy, or further disruptions in the financial and credit markets could have a material adverse effect on our business, financial condition and results of operations. Furthermore, because we typically seek to enter into long-term arrangements for the sale of a substantial portion of our coal, the average sales price we receive for our coal may lag behind any general economic recovery in the U.S.
We may be unable to obtain, maintain or renew permits, licenses or leases necessary for our operations, which would materially reduce our production, cash flow and profitability.
Mining companies must obtain a number of permits and licenses that impose strict regulations on various environmental and operational matters in connection with coal mining. These include permits and licenses issued by various federal, state and local agencies and regulatory bodies. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by the regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing operations or the development of future mining operations. The public, including non-governmental organizations, anti-mining groups and individuals, have certain statutory rights to comment upon and submit objections to requested permits and environmental impact statements (each an "EIS") prepared in connection with applicable regulatory processes, and otherwise engage in the permitting and licensing process, including bringing citizens' lawsuits to challenge the issuance of permits, the validity of EIS or performance of mining activities. For example, the EIS and other regulatory matters associated with the West Antelope II LBA are being legally challenged by several non-governmental organizations, which could create a delay or uncertainty in acquiring the coal lease. If this or any other permits, licenses or leases are not issued or renewed in a timely fashion or at all, or if permits or leases issued or renewed are conditioned in a manner that restricts our ability to efficiently and economically conduct our mining activities, we could suffer a material reduction in our production, and our cash flow or profitability could be materially and adversely affected.
Because most of the coal in the vicinity of our mines is owned by the U.S. federal government, our future success and growth could be materially and adversely affected if we are unable to acquire or are delayed in the acquisition of additional reserves through the federal competitive leasing process.
The U.S. federal government owns most of the coal in the vicinity of our mines. Accordingly, the LBA process is the most significant means of acquiring additional reserves. There is no requirement that the federal government lease coal subject to an LBA, lease its coal at all or give preference to any LBA applicant, and our bids may compete with other coal producers' bids in the PRB. In the current coal pricing environment, LBAs are becoming increasingly more competitive and expensive to obtain, and the review process to submit an LBA for bid continues to lengthen. We expect that this trend may continue. The increasing size of potential LBA tracts may make it easier for new mining operators to enter the market on economical terms and may, therefore, increase competition for LBAs. Increased opposition from non-governmental organizations and other third parties may also lengthen, delay or complicate the LBA process. For example, the West Antelope II LBA is subject to pending legal challenges filed in 2010 against the BLM and the Secretary of the Interior by environmental organizations. In order to win a lease in the LBA process and acquire additional coal, our bid for a coal tract must meet or exceed the fair market value of the coal based on the internal estimates of the BLM, which they do not publish. We have maintained a history of timely payments related to our LBAs. If we are unable to maintain our "good payer" status, we would be required to seek bonding for any remaining payments.
The LBA process also requires us to acquire rights to mine from surface owners overlying the coal, and these rights are becoming increasingly more difficult and costly to acquire. Certain federal regulations provide a specific class of surface owners, also known as qualified surface owners (each, a "QSO"), with the ability to prohibit the BLM from leasing its coal. For example, in connection with a pending LBA that we nominated for our Cordero Rojo mine, the BLM has indicated that certain surface owners satisfy the regulatory definition of QSO. If a QSO owns the land overlying a coal tract, federal laws prohibit us from leasing the coal tract without first securing surface rights to the land, or purchasing the surface rights from the QSO. This right of QSOs allows them to exercise significant influence over negotiations to acquire surface rights and can delay the LBA process or ultimately
prevent the acquisition of an LBA. If we are unable to successfully negotiate access rights with QSOs at a price and on terms acceptable to us, we may be unable to acquire LBAs for coal on land owned by the QSO. If the prices to acquire land owned by QSOs increase, it could materially and adversely affect our profitability.
Excess production and production capacity in the coal industry could put downward pressure on coal prices and, as a result, materially and adversely affect our revenues and profitability.
During the mid-1970s and early 1980s, increased demand for coal attracted new investors to the coal industry in the PRB, spurred the development of new mines and resulted in additional production capacity throughout the industry, all of which led to increased competition and lower coal prices. Increases in coal prices during recent periods encouraged the development of expanded capacity by coal producers. Some of these planned capacity increases and existing production plans were delayed or reduced due to coal price reductions since mid-2008 and the concurrent global economic downturn. However, these capacity increases may be restarted. Any overcapacity and increased production in the future could materially reduce coal prices and, therefore, materially reduce our revenues and profitability.
Our coal mining operations are subject to operating risks, which could result in materially increased operating expenses and decreased production levels and could materially and adversely affect our results of operations.
We mine coal at surface mining operations located in Wyoming and Montana. Our coal mining operations are subject to a number of operating risks. Because we maintain very little produced coal inventory, certain conditions or events could disrupt operations, adversely affect production and shipments and increase the cost of mining at particular mines for varying lengths of time, which could have a material adverse effect on our results of operations. These conditions and events include, among others:
•poor mining conditions resulting from geological, hydrologic or other conditions, which may cause instability of highwalls or spoil-piles or cause damage to nearby infrastructure;
•mining and plant equipment failures and unexpected maintenance problems;
•adverse weather and natural disasters, such as heavy rains, flooding and other natural events affecting operations, transportation or customers;
•the unavailability of raw materials, equipment (including heavy mobile equipment) or other critical supplies such as tires and explosives, fuel, lubricants and other consumables of the type, quantity and/or size needed to meet production expectations;
•the capacity of, and proximity to, rail transportation facilities and rail transportation delays or interruptions, including derailments;
•delays, challenges to, and difficulties in acquiring, maintaining or renewing necessary permits, including environmental permits, or mining or surface rights;
•delays or difficulties in, the unavailability of, or unexpected increases in the cost of acquiring, developing and permitting new LBA acquisitions from the federal government and other new mining reserves and surface rights, including challenges by non-governmental or environmental organizations or other third parties;
•competition and/or conflicts with other natural resource extraction activities and production within our operating areas, such as coalbed methane extraction or oil and gas development;
•a major incident at a mine site that causes all or part of the operations of a mine to cease for some period of time;
•current and future health, safety and environmental regulations or changes in interpretations of current regulations, including the classification of plant and animal species near our mines, including the potential listing of the sage grouse and the mountain plover, as endangered or threatened species;
•inability to acquire or maintain adequate financial sureties for mining and reclamation purposes or to meet other governmental or private bonding requirements; and
•the value of the U.S. dollar relative to other currencies, particularly where imported products are required for the mining process, such as tires and petroleum products.
These changes, conditions and events may materially increase our cost of mining and delay or halt production at particular mines either permanently or for varying lengths of time, which could have a material adverse effect on our results of operations.
Decreases in demand for electricity resulting from economic, weather changes or other conditions could adversely affect coal prices and materially and adversely affect our results of operations.
Our coal customers primarily use our coal as fuel for domestic electricity generation. Overall economic activity and the associated demands for power by industrial users can have significant effects on overall electricity demand. An economic slowdown can significantly slow the growth of electricity demand and could result in contraction of demand for coal. Weather patterns can also greatly affect electricity demand. Extreme temperatures, both hot and cold, cause increased power usage and, therefore, increased generating requirements from all sources. Mild temperatures, on the other hand, result in lower electrical demand, which allows generators to choose the sources of power generation when deciding which generation sources to dispatch. Any downward pressure on coal prices, due to decreases in overall demand or otherwise, including changes in weather patterns, would materially and adversely affect our results of operations.
The use of alternative energy sources for power generation could reduce coal consumption by U.S. electric power generators, which could result in lower prices for our coal, could reduce our revenues and materially and adversely affect our business and results of operations.
In 2010, we sold approximately 96% of our coal to domestic electric power generators. Domestic electric power generation accounted for approximately 93% of all U.S. coal consumption from October 2009 through September 2010, according to the U.S. Energy Information Administration (the "EIA"). The amount of coal consumed for U.S. electric power generation is affected by, among other things:
•the location, availability, quality and price of alternative energy sources for power generation, such as natural gas, fuel oil, nuclear, hydroelectric, wind and solar power;
•technological developments, including those related to alternative energy sources; and
•subsidies or legal mandates designed to encourage the use of alternative energy sources.
Gas-fired generation has the potential to displace coal-fired generation, particularly from older, less efficient coal-powered generators. We expect that many of the new power plants needed to meet increasing demand for domestic electricity generation will be fired by natural gas, because gas-fired plants are cheaper to construct, and permits to construct these plants are easier to obtain as natural gas is seen as having a lower environmental impact than coal-fired generators. In recent periods, governmental regulators at the federal, state and local levels have shown increased interest in limiting greenhouse gas ("GHG") emissions. This has resulted in increased regulation of coal mining and of coal-fired power plants and other end-users of coal, increasing the cost of burning coal compared to alternative energy sources. In addition, environmental activists concerned with climate change issues have attempted to use the regulatory and judicial processes to block the construction of new coal-fired
power plants or capacity expansions to existing plants. Further, state and federal mandates for increased use of electricity from renewable energy sources could have an impact on the market for our coal. Many states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard. Although none of these federal proposals have been enacted to date, the current Administration has indicated its support for a federal renewable energy standard as part of energy and climate change legislative initiatives. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reduction in the amount of coal consumed by U.S. electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.
New and potential future regulatory requirements and public concerns relating to GHG emissions could affect our customers and could reduce the demand for coal as a fuel source and cause coal prices and sales of our coal to materially decline.
One major by-product of burning coal is carbon dioxide, which is considered a GHG and is a major source of regulatory attention with respect to global warming, also known as climate change. Climate change continues to attract public and scientific attention, and increasing government attention is being paid to reducing GHG emissions, including from coal-fired power plants.
There are many regulatory approaches currently in effect or being considered to address GHGs, including possible future U.S. treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program and regulation by the U.S. Environmental Protection Agency (the "EPA").
•The current Administration has indicated its support for a mandatory cap-and-trade program to reduce GHG emissions, and the U.S. Congress has considered various proposals to reduce GHG emissions, mandate electricity suppliers to use renewable energy sources to generate a certain percentage of power and require energy efficiency measures. For example, in June 2009, the U.S. House of Representatives passed a comprehensive climate change and energy bill, the American Clean Energy and Security Act.
•In September 2009, the EPA promulgated a rule requiring certain emitters of GHGs, including coal-fired power plants, to monitor and report their GHG emissions to the EPA. In addition, following the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA, the EPA has declared that anthropogenic GHGs "endanger" public health and welfare and issued a series of rules requiring extensive regulation, starting January 2, 2011, of GHG emissions from mobile sources and stationary sources, including imposing new permitting requirements and obligations to use best available control technology for the reduction of GHG emissions whenever certain stationary sources, such as power plants, are built or significantly modified.
•State and regional climate change initiatives intended to limit or affect the emission of GHG emissions from certain sources, such as the Regional Greenhouse Gas Initiative covering certain northeastern and mid-Atlantic states, the Western Climate Initiative, the Midwestern Greenhouse Gas Reduction Accord and the California Global Warming Solutions Act, either have already taken effect or may take effect in the foreseeable future.
•The State of California approved a fee to be paid by certain emitters of GHGs, and other jurisdictions have or are also considering imposing similar fees or taxes.
The permitting of new coal-fired power plants has also recently been contested, at times successfully, by state regulators and environmental organizations due to concerns related to GHG emissions from the new plants. Additionally, at least one U.S. federal appeals court reinstated a lawsuit permitting individuals, state attorneys general and others to pursue claims against industrial companies on the basis that they have created a public nuisance due to their emissions of carbon dioxide and its alleged effects on climate (e.g. sea level and storm severity).
Climate change initiatives and other efforts to reduce GHG emissions like those described above or otherwise may require additional controls on coal-fired power plants and industrial boilers may cause some users of coal to switch from coal to a lower carbon fuel and may result in the closure of coal-fired power plants or in reduced construction of new plants. Any switching of fuel sources away from coal, closure of existing coal-fired power plants, or reduced construction of new coal-fired power plants could have a material adverse effect on demand for and prices received for our coal.
Our business requires substantial capital investment and maintenance expenditures, which we may be unable to provide.
Our business plan and strategy are dependent upon our acquisitions of additional reserves, which require substantial capital expenditures to acquire additional coal leases. We also require capital for, among other purposes, acquisition of surface rights, equipment and the development of our mining operations, capital renovations, maintenance and expansions of plants and equipment and compliance with environmental laws and regulations. To the extent that cash on hand, cash generated internally and cash available under our credit facility are not sufficient to fund capital requirements, we will require additional debt and/or equity financing. However, additional debt or equity financing may not be available to us or, if available, may not be available on satisfactory terms. Additionally, our debt instruments may restrict our ability to obtain such financing. If we are unable to obtain additional capital, we may not be able to maintain or increase our existing production rates and we could be forced to reduce or delay capital expenditures or change our business strategy, sell assets or restructure or refinance our indebtedness, all of which could have a material adverse effect on our business or financial condition.
If we are unable to acquire or develop additional coal reserves that are economically recoverable, our profitability and future success and growth may be materially and adversely affected.
Our profitability depends substantially on our ability to mine, in a cost-effective manner, coal reserves that possess the quality characteristics our customers desire. Because our reserves decline as we mine our coal, our future success and growth depend upon our ability to acquire additional coal that is economically recoverable. If we fail to acquire or develop additional reserves, our existing reserves will eventually be depleted. Furthermore, any significant delay in acquiring reserves, due to delays in the federal competitive leasing process or otherwise, could negatively impact our production rate. As a result, to maintain our production capacity and competitive position, we will need to acquire significant additional coal reserves through the federal competitive leasing process that can be mined on an economically recoverable basis.
Our ability to obtain additional coal reserves in the future could also be limited by the availability of cash we generate from our operations or available financing, restrictions under our debt instruments, competition from other coal companies for properties, the lack of suitable acquisition or LBA opportunities, the delay in the federal leasing process caused by third-party legal challenges or the inability to acquire coal properties or LBAs on commercially reasonable terms. In addition, we may not be able to mine future reserves as profitably as we do at our current operations. Furthermore, the price we receive for our coal impacts the economic recoverability of our existing coal. Our ability to develop economically recoverable reserves will be materially adversely impacted if prices for coal sold decrease significantly.
If we are unable to acquire surface rights to access our coal, we may be unable to obtain a permit to mine coal we own and may be required to employ expensive techniques to mine around those sections of land we cannot access in order to access other sections of coal reserves, which could materially and adversely affect our business and our results of operations.
After we acquire coal through the LBA process or otherwise, we are required to obtain a permit to mine the coal through the applicable state agencies prior to mining the acquired coal. In part, the permitting requirements provide that, under certain circumstances, we must obtain surface owner consent if the surface estate has been split from the mineral estate, which is commonly known as a "split estate." We have in the past and may in the future be required to negotiate with multiple parties for the surface access that overlies coal we acquired through the LBA process or otherwise. If we are unable to successfully negotiate surface access with any of these surface owners, or do so on commercially reasonable terms, we may be denied a permit to mine some of our coal or may find that we cannot mine the coal at a profit. If we are denied a permit, this would create significant delays in our mining operations and materially and adversely impact our business and results of operations. Furthermore, if we determine to alter our plans to mine around the affected areas, we could incur significant additional costs to do so, which could increase our operating expenses considerably and could materially and adversely affect our results of operations.
We may be unable to acquire state leases for coal, or to do so on a cost-effective basis, which could materially and adversely affect our business strategy and growth plans.
We acquire a small percentage of our coal through state leasing processes. Nearly all of the state leases in Wyoming have already been acquired by various mining operations in the PRB, including ours. If, as part of our growth strategy, we desire to expand our operations into areas requiring state leases, we may be required to negotiate with competing Wyoming mining operations. If we are unable to do so on a cost-effective basis, our business strategy could be adversely affected. We do not typically acquire state leases in Montana significantly in advance of mining operations due to the complexity of the leasing process in Montana.
Extensive environmental regulations, including existing and potential future regulatory requirements relating to air emissions, affect our customers and could reduce the demand for coal as a fuel source and cause coal prices and sales of our coal to materially decline.
The operations of our customers are subject to extensive environmental regulation particularly with respect to air emissions. For example, the federal Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. A series of more stringent requirements relating to particulate matter, ozone, haze, mercury, sulfur dioxide, nitrogen oxide and other air pollutants recently has been adopted and/or is expected to be proposed or become effective in the near future. In addition, federal and state mandates and incentives designed to encourage energy efficiency and the use of alternative energy sources have been proposed and implemented in recent years. Concerted conservation efforts that result in reduced electricity consumption could cause coal prices and sales of our coal to materially decline.
Considerable uncertainty is associated with these air emissions initiatives. New regulations are in the process of being developed, and many existing and potential regulatory initiatives are subject to review by federal or state agencies or the courts. Stringent air emissions limitations are either in place or are likely to be imposed in the short to medium term, and these limitations will likely require significant emissions control expenditures for many coal-fired power plants. As a result, these power plants may switch to other fuels that generate fewer of these emissions or may install more effective pollution control equipment that reduces the need for low-sulfur coal, possibly reducing future demand for coal and resulting in a reduced need to construct new coal-fired power plants. Any switching of fuel
sources away from coal, closure of existing coal-fired power plants, or reduced construction of new coal-fired power plants could have a material adverse effect on demand for, and prices received for, our coal. Alternatively, less stringent air emissions limitations, particularly related to sulfur, to the extent enacted, could make low-sulfur coal less attractive, which could also have a material adverse effect on the demand for, and prices received for, our coal.
Our customers are also subject to other existing and potential environmental regulations, such as EPA's publication in June 2010 of proposed regulations for the management and disposal of coal combustion by-products. While we are unable to determine the likely ultimate regulatory requirements, any significant changes in the management of coal combustion by-products could require our customers to comply with more stringent storage and disposal requirements, which in turn could increase their costs and reduce the demand for our coal.
Extensive environmental laws and regulations impose significant costs on our mining operations, and future laws and regulations could materially increase those costs or limit our ability to produce and sell coal.
The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to environmental matters, such as:
•limitations on land use;
•mine permitting and licensing requirements;
•reclamation and restoration of mining properties after mining is completed;
•management of materials generated by mining operations;
•the storage, treatment and disposal of wastes;
•remediation of contaminated soil and groundwater;
•air quality standards;
•water pollution;
•protection of human health, plant-life and wildlife, including endangered or threatened species;
•protection of wetlands;
•the discharge of materials into the environment; and
•the effects of mining on surface water and groundwater quality and availability.
The costs, liabilities and requirements associated with the laws and regulations related to these and other environmental matters may be significant and time-consuming and may delay commencement or continuation of exploration or production operations. Because of the extensive regulatory environment in which we operate, we cannot assure complete compliance with all laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. We may incur material costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. If we are pursued for sanctions, costs and liabilities in respect of these matters, our mining operations and, as a result, our profitability could be materially and adversely affected.
New legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations, including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us to change
operations significantly or incur increased costs. Such changes could have a material adverse effect on our financial condition and results of operations.
Our management team has limited experience managing our business as a stand-alone public company, and if they are unable to manage our business as a stand-alone public company, our business may be harmed.
We have historically operated as part of Rio Tinto. The majority of our management team has limited experience managing a business on a stand-alone basis or as a public company. If we are unable to manage and operate our company as a stand-alone public company, our business and results of operations will be adversely affected.
We are incurring increased costs as a result of being a public company, and the requirements of being a public company may divert management's attention from our business. If we are unable to achieve and maintain effective internal controls, our operating results and financial condition could be harmed.
As a public company, we incur significant legal, accounting and other expenses that we did not incur as a subsidiary of Rio Tinto. In addition, we are subject to a number of additional requirements, including the reporting requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), the Sarbanes-Oxley Act of 2002 (the "Sarbanes-Oxley Act") and the listing standards of New York Stock Exchange. These requirements have caused us to incur increased costs and placed increased demands on our systems and resources. The Exchange Act requires, among other things, that we file annual, quarterly and current reports with respect to our business and financial condition. The Sarbanes-Oxley Act requires, among other things, that we maintain effective disclosure controls and procedures and internal control over financial reporting, and also requires that our internal control over financial reporting be assessed by management and attested to by our auditors as of December 31 of each year. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal control over financial reporting, significant resources and management oversight will be required. As a result, our management's attention might be diverted from other business concerns, which could have a material adverse effect on our business, prospects, financial condition and results of operations.
We identified material weaknesses in our internal controls over financial reporting that contributed to a restatement of our 2005, 2006 and 2007 consolidated financial statements and June 30, 2008, interim consolidated financial statements. If not remediated satisfactorily, these material weaknesses could result in further material misstatements in our consolidated financial statements in future periods.
For purposes of filing our registration statement on Form S-1 in connection with our IPO, we prepared consolidated financial statements as of December 31, 2007 and 2008 and for each of the three years in the period ended December 31, 2008 in accordance with U.S. GAAP. During this process, we identified material weaknesses in our internal controls over financial reporting that contributed both to a restatement of our 2005, 2006 and 2007 consolidated financial statements and June 30, 2008 interim consolidated financial statements. Specifically, as a subsidiary of Rio Tinto, we were not required to and we did not maintain a sufficient complement of personnel with an appropriate level of accounting, taxation, and financial reporting knowledge, experience and training in the application of U.S. GAAP commensurate with our financial reporting requirements on a stand-alone basis and the complexity of our operations and transactions. We also did not maintain an adequate system of processes and internal controls sufficient to support our financial reporting requirements and produce timely and accurate U.S. GAAP consolidated financial statements consistent with being a stand-alone public company.
In preparation for the filing of our 2009 Form 10-K, management performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2009, and concluded that the previously identified material weaknesses were not yet remediated.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. A deficiency in internal control over financial reporting exists when the design or operation of a control does not allow management or employees, in the normal course of performing their assigned functions, to prevent or detect misstatements on a timely basis.
We have implemented changes and improvements in our disclosure controls and procedures and our internal control over financial reporting to remediate the control deficiencies that gave rise to the material weaknesses. If we experience future material weaknesses, investors could lose confidence in our financial reporting, particularly if such weaknesses result in a restatement of our financial results, and our stock price could decline.
If our highwalls or spoil-piles fail, our mining operations and ability to ship our coal could be impaired and our results of operations could be materially and adversely affected.
Our operations could be adversely affected and we may be unable to produce coal if our highwalls fail due to conditions, which may include geological abnormalities, poor ground conditions, water or blasting shocks, among others. In addition to making it difficult and more costly to recover coal, a highwall failure could also damage adjacent infrastructure such as roads, power lines, railways and gas pipelines. Further, in-pit spoil-pile failure due to conditions such as material type, water ingress, floor angle, floor roughness, spoil volume or otherwise, can impact coal removal, reduce coal recovery, increase our costs or interrupt our production and shipments. Highwall and spoil-pile failures could materially and adversely affect our operations, thereby reducing our profitability.
Major equipment and plant failures could reduce our ability to produce and ship coal and materially and adversely affect our results of operations.
We depend on several major pieces of equipment and plants to produce and ship our coal, including draglines, shovels, coal crushing plants, critical conveyors, major transformers and coal silos. If any of these pieces of equipment or plants suffered major damage or were destroyed by fire, abnormal wear, flooding, incorrect operation, damage from highwall or spoil-pile failures or otherwise, we may be unable to replace or repair them in a timely manner or at a reasonable cost, which would impact our ability to produce and ship coal and materially and adversely affect our results of operations.
Significant increases in royalties or in severance and production taxes we pay on the coal we produce could materially and adversely affect our results of operations.
We pay federal, state and private royalties and federal, state and county production taxes on the coal we produce. A substantial portion of our royalties and production taxes are levied as a percentage of gross revenues with the remaining levied on a per ton basis. For example, we pay production royalties of 12.5% of gross proceeds to the federal government. We incurred royalties and severance and production taxes which represented 30.5% and 29.1% of proceeds from the coal we produced for the years ended December 31, 2010 and 2009, respectively. If royalties or severance and production tax rates were to significantly increase or if we are required to make additional payments as a result of governmental audits, our results of operations could be materially and adversely affected.
In addition, the Wyoming state severance tax is significantly less than the state severance tax in Montana. Because a substantial portion of our operations are in Wyoming and therefore subject to the more favorable Wyoming severance tax rate, if Wyoming were to increase this tax or any other tax applicable solely to our Wyoming operations, we may be significantly impacted and our results of operations could be materially and adversely affected.
Increases in the cost of raw materials and other industrial supplies, or the inability to obtain a sufficient quantity of those supplies, could increase our operating expenses, disrupt or delay our production and materially and adversely affect our profitability.
We use considerable quantities of explosives, petroleum-based fuels, tires, steel and other raw materials, as well as spare parts and other consumables in the mining process. If the prices of steel, explosives, tires, petroleum products or other materials increase significantly or if the value of the U.S. dollar declines relative to foreign currencies with respect to certain imported supplies or other products, our operating expenses will increase, which could materially and adversely impact our profitability. Additionally, a limited number of suppliers exist for certain supplies, such as explosives and tires, as well as certain mining equipment, and any of our suppliers may divert their products to buyers in other mines or industries or divert their raw materials to produce other products that have a higher profit margin. Shortages in raw materials used in the manufacturing of supplies and mining equipment, which, in some cases, do not have ready substitutes, or the cancellation of our supply contracts under which we obtain these raw materials and other consumables, could limit our ability to obtain these supplies or equipment. As a result, we may not be able to acquire adequate replacements for these supplies or equipment on a cost-effective basis or at all, which could also materially increase our operating expenses or halt, disrupt or delay our production.
Significant increases in the price of diesel fuel could materially and adversely affect our earnings.
Operating expenses at our mining locations are sensitive to changes in certain variable costs, particularly diesel fuel prices, which are our largest variable cost after personnel costs. Any increase in the price we pay for diesel fuel will have a negative impact on our results of operations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations-Cost of Product Sold" within Item 7 and "Quantitative and Qualitative Disclosures About Market Risk-Commodity Price Risks" in Item 7A.
Conflicts of interest with competing holders of mineral rights could materially and adversely affect our ability to mine coal or do so on a cost-effective basis.
The federal government leases many different mineral rights in addition to coal, such as coalbed methane, natural gas and crude oil reserves. Some of these minerals are located on, or are adjacent to, some of our coal and LBA areas, potentially creating conflicting interests between us and the lessees of those interests. If conflicting interests arise, we may be required to negotiate our ability to mine with the holder of the competing mineral rights. If we are unable to reach an agreement with these holders, or do so on a cost-effective basis, we may incur increased costs and our ability to mine could be impaired, which could materially and adversely affect our business and results of operations.
Inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.
Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. We base our estimates of reserves on engineering, economic and geological data assembled and analyzed by our internal geologists and engineers. Our estimates of proven and probable coal reserves as to both quantity and quality are updated annually to reflect the production of coal from the reserves, updated geological models and mining recovery data, the tonnage contained in new lease areas acquired and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, any one of which may vary considerably from actual results. These factors and assumptions include:
•quality of the coal;
•geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine;
•the percentage of coal ultimately recoverable;
•the assumed effects of regulation, including the issuance of required permits, and taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;
•assumptions concerning the timing for the development of the reserves; and
•assumptions concerning equipment and productivity; future coal prices; operating costs, including for critical supplies such as fuel, tires and explosives; capital expenditures and development and reclamation costs.
As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary materially due to changes in the above factors and assumptions. Actual production recovered from identified reserve areas and properties, and revenues and expenditures associated with our mining operations, may vary materially from estimates. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues and/or higher than expected costs.
The majority of our coal sales contracts are forward sales contracts at fixed prices. If the production costs underlying these contracts increase, our results of operations could be materially and adversely affected.
The majority of our coal sales contracts are forward sales contracts under which customers agree to pay a specified price under their contracts for coal to be delivered in future years. The profitability of these contracts depends on our ability to adequately control the costs of the coal production underlying the contracts. These production costs are subject to variability due to a number of factors, including increases in the cost of labor, supplies or other raw materials, such as diesel fuel. Historically we have not entered into hedge or other arrangements to offset the cost variability underlying these forward sale contracts. In the future, we may enter into these types of arrangements, but we may not be successful in hedging the volatility of our costs. To the extent our costs increase but pricing under these coal sales contracts remains fixed, we will be unable to pass increasing costs on to our customers. If we are unable to control our costs, our profitability under our forward sales contracts may be impaired and our results of operations could be materially and adversely affected.
Our ability to operate our business effectively could be impaired if we fail to attract and retain key personnel.
Our ability to operate our business and implement our strategies depends, in part, on the continued contributions of our executive officers and other key employees. The loss of any of our key senior executives could have a material adverse effect on our business unless and until we find a qualified replacement. A limited number of persons exist with the requisite experience and skills to serve in our senior management positions. We may not be able to locate or employ qualified executives on acceptable terms. In addition, we believe that our future success will depend on our continued ability to attract and retain highly skilled personnel with coal industry experience. Competition for these persons in the coal industry is intense, and we may not be able to successfully recruit, train or retain qualified managerial personnel. As a public company, our future success also will depend on our ability to hire and retain management with public company experience. We may not be able to continue to employ key personnel or attract and retain qualified personnel in the future. Our failure to retain or attract key personnel could have a material adverse effect on our ability to effectively operate our business.
Our operations may affect the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, any of which could result in material liabilities to us.
Our operations use hazardous materials and generate hazardous and non-hazardous wastes. In addition, many of the locations that we own, lease or operate were used for coal mining and/or involved the generation, use, storage and disposal of hazardous substances either before or after we were involved with these locations. We may be subject to claims under federal and state statutes and/or common law doctrines for toxic torts, natural resource damages and other damages, as well as for the investigation and clean up of soil, surface water, groundwater and other media. These claims may arise, for example, out of current or former conditions at sites that we own, lease or operate currently, as well as at sites that we or predecessor entities owned, leased or operated in the past, and at contaminated third-party sites at which we have disposed of hazardous substances and waste. As a matter of law, and despite any contractual indemnity or allocation arrangements or acquisition agreements to the contrary, our liability for these claims may be joint and several, so that we may be held responsible for more than our share of any contamination, or even for the entire share.
These and similar unforeseen impacts that our operations may have on the environment, as well as human exposure to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could materially and adversely affect us.
Extensive governmental regulations pertaining to employee safety and health impose significant costs on our mining operations, which could materially and adversely affect our results of operations.
Federal and state safety and health regulations in the coal mining industry are among the most comprehensive and pervasive systems for protection of employee safety and health affecting any segment of U.S. industry. Compliance with these requirements imposes significant costs on us and can result in reduced productivity. Moreover, the possibility exists that new health and safety legislation and/or regulations and orders may be adopted that may materially and adversely affect our mining operations.
We must compensate employees for work-related injuries through our workers compensation insurance funds. If we do not make adequate provisions for our workers' compensation liabilities, it could harm our future operating results. In addition, the erosion through tort liability of the protections we are currently provided by workers' compensation laws could increase our liability for work-related injuries and materially and adversely affect our operating results. Under federal law, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and contribute to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry before January 1, 1970. The trust fund is funded by an excise tax on coal production. If this tax increases, or if we could no longer pass it on to the purchasers of our coal under our coal sales agreements, our operating costs could be increased and our results could be materially and adversely harmed. If new laws or regulations increase the number and award size of claims, it could materially and adversely harm our business.
Federal or state regulatory agencies have the authority to order certain of our mines to be temporarily or permanently closed under certain circumstances, which could materially and adversely affect our ability to meet our customers' demands.
Federal or state regulatory agencies have the authority under certain circumstances following significant health and safety incidents, such as fatalities, to order a mine to be temporarily or permanently closed. If this occurred, we may be required to incur capital expenditures to re-open the mine. In the event that these agencies order the closing of our mines, our coal sales contracts may permit us to issue force majeure notices, which suspend our obligations to deliver coal under these contracts. However, our customers may challenge our issuances of force majeure notices. If these
challenges are successful, we may have to purchase coal from third-party sources, if it is available, to fulfill these obligations, incur capital expenditures to re-open the mines and/or negotiate settlements with the customers, which may include price reductions, the reduction of commitments or the extension of time for delivery or terminate customers' contracts. Any of these actions could have a material adverse effect on our business and results of operations.
Because we produce and sell coal with low-sulfur content, a reduction in the price of sulfur dioxide emission allowances or increased use of technologies to reduce sulfur dioxide emissions could materially and adversely affect the demand for our coal and our results of operations.
Our customers' demand for our low-sulfur coal, and the prices that we can obtain for it, are affected by, among other things, the price of sulfur dioxide emission allowances. The Clean Air Act places limits on the amounts of sulfur dioxide that can be emitted by an electric power plant, among other sources, in any given year. If a plant exceeds its allowable limits, it must purchase allowances, which are tradable in the open market. Regulatory uncertainty following the action by the U.S. Court of Appeals for the District of Columbia Circuit to vacate the Clean Air Interstate Rule ("CAIR") in July 2008, and its subsequent temporary reinstatement, which established a cap-and-trade program for sulfur dioxide and nitrogen oxide emissions from power plants in certain states, caused a significant decrease in the price of sulfur dioxide allowances from 2008 to date, and delayed the installation of technology to reduce emissions at some power plants. Low prices of these emissions allowances could make our low-sulfur coal less attractive to our customers for the near-term. In July 2010, the EPA proposed the Clean Air Transport Rule ("CATR") as a replacement for CAIR. If promulgated, CATR would phase in requirements for sources of sulfur dioxide and nitrogen oxide beginning in 2012; subject sources would include power plants. Under CATR, the EPA has proposed state-specific emissions and allocation budgets and intrastate cap-and-trade mechanisms for allocations, with very limited to no interstate trading provisions in the EPA options under consideration. The effects which these intrastate and interstate provisions will have on CATR allowance markets remain uncertain. For select states, the emissions budgets will be further reduced in 2014. Coincident with these proposed changes is the finalization of revised National Ambient Air Quality Standards ("NAAQS") for nitrogen dioxide and sulfur dioxide that occurred in January 2010 and June 2010, respectively. More widespread installation by electric utilities of technology that reduces sulfur emissions could be accelerated to meet the requirements of the revised NAAQS and/or requirements from the finalization of CATR and may make high sulfur coal more competitive with our low-sulfur coal. This competition could materially and adversely affect our business and results of operations. Alternatively, compliance with the revised NAAQS and/or the finalization of CATR could entail utilization of controls in combination with low-sulfur coal. In the CATR proposal, the EPA has projected that to meet the proposed CATR requirements, utilities would need to install 11 GWs of new sulfur dioxide scrubbers in addition to those controls already planned or in place. The EPA recently published a notice of data availability and stated that the new data might impact the agency's assessment of which states contribute to pollution problems in downwind states, which in turn might lead to pressure to expand the number of states subject to the CATR. If additional states are obligated to comply with CATR, it may adversely affect the demand for our coal.
Our ability to mine and ship coal is affected by adverse weather conditions, which could have an adverse effect on our revenues.
Adverse weather conditions can impact our ability to mine and ship our coal and our customers' ability to take delivery of our coal. Lower than expected shipments by us during any period could have an adverse effect on our revenues and profitability. For example, previously our volume of coal shipments has been impacted by severe heavy rain, which reduced the capacity of the railroads by which our customers contract to transport coal from our mines. In addition, severe weather, including droughts and dust, may adversely affect our ability to conduct our mining operations.
The availability and reliability of transportation and increases in transportation costs, particularly for rail systems, could materially and adversely affect the demand for our coal or impair our ability to supply coal to our customers.
Transportation costs, particularly rail transportation costs, represent a significant portion of the total cost of coal for our customers, and the cost of transportation is a key factor in a customer's purchasing decision. Increases in transportation costs or the lack of sufficient rail capacity or availability could make coal a less competitive source of energy or could make the coal produced by us less competitive than coal produced from other regions, either of which could lead to reduced coal sales and/or reduced prices we receive for the coal.
Our ability to sell coal to our customers depends primarily upon third-party rail systems. If our customers are unable to obtain rail or other transportation services, or to do so on a cost-effective basis, our business and growth strategy could be adversely affected. Alternative transportation and delivery systems are generally inadequate and not suitable to handle the quantity of our shipments or to ensure timely delivery to our customers. In particular, much of the PRB is served by two rail carriers, and the northern PRB is only serviced by one rail carrier. The loss of access to rail capacity in the PRB could create temporary disruption until this access was restored; significantly impairing our ability to supply coal and resulting in materially decreased revenues. Our ability to open new mines or expand existing mines may also be affected by the availability and cost of rail or other transportation systems available for servicing these mines.
We are a party to certain transportation contracts. During recent periods, we have entered into an increasing number of exports whereby we enter into transportation agreements pursuant to which we arrange for rail transport and port charges. However, typically our coal customers contract for, and pay directly for, transportation of coal from the mine or port to the point of use. Disruption of these transportation services because of weather-related problems; mechanical difficulties; train derailment; bridge or structural concerns; infrastructure damage, whether caused by ground instability, accidents or otherwise; strikes; lock-outs; lack of fuel or maintenance items; fuel costs; transportation delays; accidents; terrorism or domestic catastrophe or other events could temporarily or over the long term impair our ability to supply coal to our customers and our customers' ability to take our coal and, therefore, could materially and adversely affect our business and results of operations.
If we do not maintain and grow our export sales, our results may be adversely affected.
A portion of our coal sales in recent years have been into export markets in Asia, and we seek to make additional export sales in the future to Asia and potentially other international locations. Our ability to maintain and grow our export sales revenues and margins depends on a number of factors, including the existence of sufficient and cost-effective export terminal capacity for the shipment of thermal coal to foreign markets and demand by customers in Asia and in other potential export markets for PRB coal. Our access to existing and any future terminal capacity may be adversely affected by regulatory and permit requirements, environmental and other legal challenges, public perceptions and resulting political pressures, operational issues at terminals and competition among domestic coal producers for access to limited terminal capacity, among other factors. If we fail to maintain and grow terminal capacity for the export of our coal on commercially reasonable terms, or at all, our results from our export transactions will be materially adversely affected. Foreign customer demand for PRB coal, and the prices those customers may be willing to pay for PRB coal and related transportation costs, can be affected by a variety of matters, including supplier diversity and security considerations, economic conditions and demand for electricity in the relevant markets, international energy policies and regulatory requirements, and availability and pricing for thermal coal delivered from alternative international basins.
Due to the long-term nature of our coal sales agreements, the prices we receive for our coal at any given time may not reflect the then-existing current market prices for coal.
We have historically sold most of our coal under long-term coal sales agreements, which we generally define as contracts with a term of one to five years. The remaining amount not subject to long-term coal sales agreements is sold as spot sales in term allotments of less than twelve months. For the year ended December 31, 2010 approximately 97% of our revenues were derived from coal sales that were made under long-term coal sales agreements. The prices for coal sold under these agreements are typically fixed for an agreed amount of time. Pricing in some of these contracts is subject to certain adjustments in later years or under certain circumstances, and may be below the current market price for similar type coal at any given time, depending on the time frame of the contract. As a consequence of the substantial volume of our forward sales, we have less coal available to sell under short-term contracts in order to immediately capitalize on higher coal prices, if and when they arise. At times, spot market prices have fallen below the prices established in many of our long-term coal sales agreements, and we have realized prices for our coal that are higher than the prices we would receive from sales in the spot market. However, to the extent spot market prices increase and become higher than the prices established in our long-term coal sales agreements, our ability to realize those higher prices may be restricted when customers elect to purchase additional volumes allowable under some contracts at contract prices that are lower than spot prices.
Changes in purchasing patterns in the coal industry may make it difficult for us to enter into new contracts with customers, or do so on favorable terms, which could materially and adversely affect our business and results of operations.
Although we currently sell the majority of our coal under long-term coal sales agreements, as electric utilities customers continue to adjust to increased price volatility, increased fungibility of coal products, frequently changing regulations and the increasing deregulation of their industry, some customers are becoming less willing to enter into long-term coal sales contracts. In addition, the prices for coal in the spot market have decreased at times and may be lower than the prices previously set under many of our long-term coal sales agreements. As our contracts with customers expire or are otherwise renegotiated, our customers may be less willing to extend or enter into new long-term coal sales agreements under their existing or similar pricing terms or our customers may decide to purchase fewer tons of coal than in the past.
These trends in purchasing patterns in the coal industry could continue in the future and, to the extent our customers shift away from long-term supply contracts, it will be more difficult to predict our future sales. As a result, we may not have a market for our future production at acceptable prices. The prices we receive in the spot market may be less than the contractual price an electric utility is willing to pay for a committed supply. Furthermore, spot market prices tend to be more volatile than contractual prices, which could result in decreased revenues.
If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated or be incurred sooner than anticipated.
All of our mines are surface mining operations. The Surface Mining Control and Reclamation Act ("SMCRA") and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining. We estimate our total reclamation and mine-closing liabilities based on permit requirements, engineering studies and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed periodically by our management and engineers, and by government regulators. At the Decker mine, the reclamation liability is estimated by the third-party operator. The estimated liability can change significantly if actual costs vary from our original assumptions or if governmental regulations change significantly. U.S. GAAP requires that asset retirement obligations be recorded as a liability based on fair value,
which reflects the present value of the estimated future cash flows. In estimating future cash flows, we consider the estimated current cost of reclamation and apply inflation rates and a third-party profit, as necessary. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on behalf of us. The resulting estimated reclamation and mine closure obligations could change significantly if actual amounts or the timing of those expenses change significantly from our assumptions, which could have a material adverse effect on our results of operation and financial condition.
The risk that we cannot collect payments from our customers could increase if their creditworthiness deteriorates.
The risk that we do not receive payment for coal sold and delivered increases if the continued creditworthiness of our customers declines. Recent past economic volatility and tightening credit markets increased the risk that we may not be able to collect payments from our customers or be required to continue to deliver coal even if a customer's creditworthiness deteriorates. A worsening of recent economic conditions or a prolonged global or U.S. recession could also impact the creditworthiness of our customers. If we determine that a customer is not creditworthy, we can demand credit enhancements from the customer. If we are unsuccessful or feel the credit enhancement is insufficient, we may not be required to deliver coal under the customer's coal sales contract. If we are able to withhold shipments, we may decide to sell a customer's coal on the spot market, which may be at prices lower than the contracted price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could materially and adversely affect our financial position. In addition, our customer base may change with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear for customer payment default. These new power plant owners may have credit ratings that are below investment grade, or may fall below investment grade after we enter into contracts with them. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk of payment default.
Certain provisions in our coal sales contracts may provide limited protection during adverse economic conditions or may result in economic penalties or suspension upon a failure to meet contractual requirements, any of which may cause our revenues and profits to suffer.
Most of our sales contracts contain provisions that allow for the base price of our coal in these contracts to be adjusted due to new statutes, ordinances or regulations that affect our costs related to performance. Because these provisions only apply to the base price of coal, these terms may provide only limited protection due to changes in regulations. A few of our sales contracts also contain provisions that allow for the purchase price to be renegotiated at periodic intervals. A price re-opener provision is one in which either party can renegotiate the price of the contract, sometimes at pre-determined times. Index provisions allow for the adjustment of the price based on a fixed formula. These provisions may reduce the protection available under long-term contracts from short-term coal price volatility. Price re-opener and index provisions are present in certain contracts covering our future tonnage commitments. Any adjustment or renegotiations leading to a significantly lower contract price could result in decreased revenues.
Quality and volumes for the coal are stipulated in coal sales agreements. In most cases, the annual pricing and volume obligations are fixed, although in some cases, the volume specified may vary depending on the quality of the coal. In a relatively small number of contracts, customers are allowed to vary the amount of coal taken under the contract. Most of our coal sales agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics, such as heat content, sulfur, ash and ash fusion temperature. Failure to meet these specifications can result in
economic penalties, including price adjustments, suspension, rejection or cancellation of deliveries or termination of the contracts.
Many of our contracts contain clauses that require us and our customers to maintain a certain level of creditworthiness or provide appropriate credit enhancement upon request. The failure to do so can result in a suspension of shipments under the contract. A number of our contracts also contain clauses which, in some cases, may allow customers to terminate the contract in the event of certain changes in environmental laws and regulations.
Failure to maintain our surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and materially and adversely affect our ability to mine or lease coal.
Federal and state laws require us to secure the performance of certain long-term obligations, such as mine closure or reclamation costs and federal and state workers' compensation costs, including black lung. The amount of these security arrangements is substantial with $525.0 million of surety bonds and $10.5 million of letters of credit issued as of December 31, 2010, to support reclamation and lease obligations. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand terms less favorable to us, higher fees, or additional collateral in the form of letters of credit or cash collateral upon those renewals. Because we are required by state and federal law to have these bonds in place before mining can commence or continue, our failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety bonds and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of any credit arrangements then in place.
Upon the occurrence of a force majeure, we or our customers may be permitted to temporarily suspend performance under our coal sales contracts, which could cause our revenues and profits to suffer.
Our coal sales agreements typically contain force majeure provisions allowing temporary suspension of performance by us or our customers during the duration of specified events beyond the control of the affected party, including events such as strikes, adverse mining conditions, mine closures, serious transportation problems that affect us or the buyer or unanticipated plant outages that may affect the buyer. Some contracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the buyer. As a result of the economic downturn, a greater than normal number of our customers in 2009 sought to reduce the amount of tons delivered to them under our coal sales agreements through contractual remedies, such as force majeure provisions. Agreements between our customers and the railroads servicing our mines may also contain force majeure provisions. Generally, our coal sales agreements allow our customer to suspend performance in the event that the railroad fails to provide its services due to circumstances that would constitute a force majeure. In the event that we are required to suspend performance under any of our coal sales contracts, or we are required to purchase additional tonnage during the period in which performance under the contract is suspended, our revenues and profits could be materially and adversely affected.
Acquisitions that we may undertake in the future involve a number of risks, any of which could cause us not to realize the anticipated benefits.
We have focused on strategic acquisitions and subsequent expansions of large, low-cost, low-sulfur operations in the PRB and replacement of, and additions to, our reserves through the acquisition of companies, mines and reserves. We may pursue acquisition opportunities in the future. If we are unable to successfully integrate the businesses or properties we acquire, or reserves that we lease or otherwise
acquire, our business, financial condition or results of operations could be negatively affected. Acquisition transactions involve various risks, including:
•uncertainties in assessing the strengths and potential profitability, and the related weaknesses, risks, contingent and other liabilities, of acquisition candidates;
•changes in business, industry, market or general economic conditions that affect the assumptions underlying our rationale for pursuing the acquisition;
•the inability to achieve identified operating and financial synergies anticipated to result from an acquisition;
•the potential loss of key customers, management or employees of an acquired business;
•the nature and composition of the workforce, including the acquisition of a unionized workforce;
•diversion of our management's attention from other business concerns;
•regulatory challenges for completing and operating the acquired business, including opposition from environmental groups or regulatory agencies;
•environmental or geological problems in the acquired properties, including factors that make the coal unsuitable for intended customers due to ash, heat value, moisture or contaminants;
•inability to acquire sufficient surface rights to enable extraction of the coal resources;
•outstanding permit violations associated with acquired assets;
•difficulties or unexpected issues arising from our evaluation of internal control over financial reporting of the acquired business; and
•risks related to operating in new jurisdictions, including increased exposure to foreign government and currency risks with respect to any international acquisitions.
Any one or more of these factors could cause us not to realize the benefits we might anticipate from an acquisition. Moreover, any acquisition opportunities we pursue could materially increase our liquidity and capital resource needs and may require us to incur indebtedness, seek equity capital or both. We may not be able to satisfy these liquidity and capital resource needs on acceptable terms or at all. In addition, future acquisitions could result in our assuming significant long-term liabilities relative to the value of the acquisitions.
We do not operate the Decker mine and our results of operations could be adversely affected if the third-party mine operator fails to effectively operate the mine or if the other 50% owner fails to perform its obligations. In addition, our credit arrangements may limit our ability to contribute cash to the Decker mine.
Through our indirect, wholly-owned subsidiary, we hold a 50% non-operating interest in the Decker mine in Montana through a joint venture agreement with the other 50% owner. The Decker mine is operated by a third-party mine operator. While we participate in the management committee of the Decker mine under the terms of the joint venture agreement, we do not control and our employees do not participate in the day-to-day operations of the Decker mine. If the third-party mine operator fails to operate the Decker mine effectively, our results of operations could be adversely affected.
We share the profits, operating expenses, reclamation obligations and liabilities and assets associated with the Decker mine equally with the other 50% owner. Under the terms of the joint venture agreement, we are required to contribute cash or other property and equipment as may be necessary to operate the business. While capital contributions to the Decker joint venture have historically been made at the discretion of the management committee, under the terms of the joint venture agreement we may be required to contribute our proportional share of funds to carry on the
business of the joint venture or to cover liabilities. In the event that either 50% owner does not contribute its share of operating expenses, including reclamation expenses when due, or other liabilities, the other owner is not required to assume their obligation. However, we may have joint and several liability as a matter of law for these expenses and other liabilities, including for operational liabilities. Accordingly, our financial obligations with respect to the Decker mine are subject to the creditworthiness of the other 50% owner, which is outside of our control. In addition, if we do not provide our proportional share or the other 50% owner does not provide its proportional share, our interest in the profits from the Decker mine will be adjusted proportionally. CPE Resources' current debt instruments and future credit arrangements may limit our ability to make contributions to the Decker joint venture.
A shortage of skilled labor in the mining industry could reduce labor productivity and increase costs, which could materially and adversely affect our business and results of operations.
Efficient coal mining using modern techniques and equipment requires skilled laborers in multiple disciplines such as electricians, equipment operators, mechanics, engineers and welders, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. In the future, we may utilize a greater number of external contractors for portions of our operations. The costs of these contractors have historically been higher than that of our employed laborers. If coal prices decrease in the future and/or our labor and contractor prices increase, or if we experience materially increased health and benefit costs with respect to our employees, our results of operations could be materially and adversely affected.
Our work force could become unionized in the future, which could adversely affect the stability of our production and materially reduce our profitability.
All of our mines, other than the Decker mine, which we do not operate, are operated by non-union employees. Our employees have the right at any time under the National Labor Relations Act to form or affiliate with a union, and in the past, unions have conducted limited organizing activities in this regard. If our employees choose to form or affiliate with a union and the terms of a union collective bargaining agreement are significantly different from our current compensation and job assignment arrangements with our employees, these arrangements could adversely affect the stability of our production and materially reduce our profitability. In addition, even if our managed operations remain non-union, our business may still be adversely affected by work stoppages at unionized companies or unionized transportation and service providers.
We hold a 50% interest in the Decker mine, which has union members. These union-represented employees could strike, which could adversely affect production at the Decker mine, increase its costs and disrupt shipments of coal from the Decker mine to its customers, all of which could materially and adversely affect its profitability and the value of our investment in the Decker joint venture.
Provisions in our federal and state lease agreements, or defects in title or the loss of a leasehold interest in certain property or reserves or related surface rights, could limit our ability to mine our coal reserves.
The vast majority of our coal interests are acquired by lease from state or federal governments. Under these leases, the BLM or the applicable state regulatory agency can terminate the lease prior to the expiration of its term if the leased coal reserves are not diligently developed during the initial 10 years of the leases or if certain other terms of the leases are not complied with, including the requirement to produce a minimum quantity of coal or pay a minimum advance production royalty, if applicable. If any of our leases are terminated, we would be unable to mine the affected coal and our business and results of operations could be materially adversely affected.
Furthermore, a title defect on any lease, whether private or through a governmental entity, or the surface rights related to any of our reserves could adversely affect our ability to mine the associated coal reserves. Consistent with industry practice, we conduct only limited investigations of title to our coal properties prior to leasing. Title to properties leased from private third parties is not usually fully verified until we make a commitment to develop a property, which may not occur until we have obtained the necessary permits and completed exploration of the property. In addition, these leasehold interests may be subject to superior property rights of other third parties. Title or other defects in surface rights held by us or other third parties could impair our ability to mine the associated coal reserves or cause us to incur unanticipated costs.
Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war may materially and adversely affect our business and results of operations.
Terrorist attacks and threats, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the U.S. or its allies, or military or trade disruptions affecting our customers may significantly affect our operations and those of our customers. Strategic targets such as energy-related assets and transportation assets may be at greater risk of future terrorist attacks than other targets in the U.S. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business and results of operations, including from delays or losses in transportation, decreased sales of our coal or extended collections from customers that are unable to timely pay us in accordance with the terms of their supply agreement.
Risks Related to Our Indebtedness
Our substantial indebtedness could adversely affect our results of operations and financial condition and prevent us from fulfilling our financial obligations.
At December 31, 2010, we had $600 million of senior notes outstanding and approximately $8.1 million of other long-term debt incurred in connection with land acquisitions. In addition, at December 31, 2010, $10.5 million of capacity under our $400 million revolving credit facility was being used for letters of credit securing our reclamation obligations reducing the capacity under the revolving credit facility to $389.5 million. Our outstanding indebtedness could have important consequences such as:
•limiting our ability to obtain additional financing to fund growth, such as mergers and acquisitions; working capital; capital expenditures; debt service requirements; LBA payments or other cash requirements;
•requiring much of our cash flow to be dedicated to interest obligations and making it unavailable for other purposes;
•with respect to any indebtedness under the revolving credit facility or other variable rate debt, exposing us to the risk of increased interest costs if the underlying interest rates rise on our variable rate debt;
•limiting our ability to invest operating cash flow in our business (including to obtain new LBAs or make capital expenditures) due to debt service requirements;
•causing us to need to sell assets and properties at an inopportune time;
•limiting our ability to compete effectively with companies that are not as leveraged and that may be better positioned to withstand economic downturns;
•limiting our ability to acquire new coal reserves and/or LBAs and plant and equipment needed to conduct operations; and
•limiting our flexibility in planning for, or reacting to, and increasing our vulnerability to, changes in our business, the industry in which we operate and general economic and market conditions.
If our indebtedness is further increased, the related risks that we now face, including those described above, could intensify. Moreover, these risks also apply to certain of CPE Resources' domestic restricted subsidiaries that are guarantors of CPE Resources' indebtedness and may apply to us directly if we become a guarantor of CPE Resources' debt in the future. In addition to the principal repayments on outstanding debt, we have other demands on our cash resources, including significant maintenance and other capital expenditures, including LBAs, and operating expenses and required payments under the Tax Receivable Agreement (See "Risk Factors-Risks Related to Our Corporate Structure and the IPO Structuring Transaction"). Our ability to pay our debt depends upon the operating performance of our business. In particular, economic conditions could cause revenues to decline, and hamper our ability to repay indebtedness. If we do not have enough cash to satisfy our debt service obligations, we may be required to refinance all or part of our debt, sell assets, limit certain capital expenditures, including LBAs, or reduce spending or we may be required to issue equity. We may not be able to, at any given time, refinance our debt or sell assets and we may not be able to, at any given time, issue equity, in either case on acceptable terms or at all.
We may be able to incur substantially more debt. This could exacerbate the risks associated with our substantial indebtedness.
We and our subsidiaries may be able to incur substantially more debt in the future. Although CPE Resources' debt instruments contain restrictions on our incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions and, under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. We are able to incur up to $400 million (subject to reduction by the amount of our letters of credit) in total indebtedness under our revolving credit facility (with a potential incremental increase of up to $50 million, subject to certain conditions). Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness. To the extent new debt or new obligations are added to our current levels, the risks described above could substantially increase and we may not be able to meet all of our debt obligations.
If we are unable to comply with the covenants or restrictions contained in CPE Resources' debt instruments, the lenders could declare all amounts outstanding under those instruments to be due and payable, which could materially and adversely affect our financial condition.
The debt instruments include covenants that, among other things, restrict our ability to dispose of assets, incur additional indebtedness, pay dividends or make other restricted payments, create liens on assets, make investments, loans or advances, make acquisitions, engage in mergers or consolidations and engage in certain transactions with affiliates. The debt instruments also include change of control provisions that accelerate or may require the repurchase of outstanding indebtedness in the event of certain change of control events. The debt instruments also require compliance with various financial covenants. Because CPE Resources (which entered into the debt instruments) is our only direct operating subsidiary, complying with these restrictions may prevent us from taking actions that we believe would help us to grow our business. These restrictions could limit our ability to plan for or react to market conditions or meet extraordinary capital needs or otherwise restrict corporate activities.
The breach of any of the covenants or restrictions, unless cured within the applicable grace period, would result in a default under the debt instruments that would permit the lenders to declare all amounts outstanding to be due and payable, together with accrued and unpaid interest. In such an
event, we may not have sufficient assets to repay such indebtedness. As a result, any default could have serious consequences to our financial condition. An event of default or an acceleration under one of our debt instruments could also cause a cross-default or cross-acceleration of another debt instrument or contractual obligation, which would adversely impact our liquidity.
In addition, failure to comply with any of the covenants in our existing or future debt instruments could result in a default under those debt instruments and under other agreements containing cross-default provisions. A default would permit lenders to accelerate the maturity of the debt under these debt instruments and to foreclose upon any collateral securing the debt. Under these circumstances, we might not have sufficient funds or other resources to satisfy all of our obligations. In addition, the limitations imposed by the debt instruments on our ability to incur additional debt and to take other actions might significantly impair our ability to obtain other financing. We may not be granted waivers or amendments to these debt instruments if for any reason we are unable to comply with these debt instruments, and we may not be able to refinance our debt on terms acceptable to us, or at all.
Provisions in CPE Resources' debt instruments could discourage an acquisition of us by a third party.
Certain provisions of CPE Resources' debt instruments could make it more difficult or more expensive for a third party to acquire us. Upon the occurrence of certain transactions constituting a "change in control" as defined in the indenture, holders of the senior notes could require us to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase.
Risks Related to Our Corporate Structure and Our IPO Structuring Transactions
We are required to pay RTEA for most of the tax benefits we may claim as a result of the tax basis step-up we received in connection with our IPO, related IPO structuring transactions and Secondary Offering. In certain cases, payments to RTEA may be accelerated or exceed our actual cash tax savings. These provisions may deter a change in control of our company.
In connection with our IPO and the acquisition of our membership units of CPE Resources, we entered into the Tax Receivable Agreement with RTEA that requires us to pay to RTEA approximately 85% of the amount of cash tax savings, if any, that we realize as a result of the increases in tax basis that we obtained in connection with the initial acquisition of our interest in CPE Resources, our subsequent acquisition of RTEA's remaining units in CPE Resources, as well as payments made by us under the Tax Receivable Agreement. Due to the size of the increases in the tax basis of our share of CPE Resources' tangible and intangible assets, as well as the increase in our basis in the equity of CPE Resources' subsidiaries and assets held by those subsidiaries, we expect to make substantial payments to RTEA under the Tax Receivable Agreement. As a result of our acquisition of RTEA's remaining units in CPE Resources we have received a further step-up in our tax basis and, accordingly, our obligations under the Tax Receivable Agreement to pay RTEA 85% of any benefits we receive as a result of such further step-up has significantly increased. Our obligation may further increase if there are changes in law, including the increase of current corporate income tax rates. The payment obligations under the Tax Receivable Agreement are not conditioned upon RTEA's or its affiliate's continued ownership of an interest in CPE Resources or our available cash resources. Based on the tax basis of our assets as of December 31, 2010 and CPE Resources' operating plan, the future payments under the Tax Receivable Agreement are estimated to be approximately $190.1 million in the aggregate and are estimated to be payable over the next 20 years. This estimate is based on assumptions related to our business that could change, and the actual payments could differ materially from this estimate. Payments would be greater if we generate income significantly in excess of the amounts used in our operating plan, for example, because we acquire additional LBAs beyond our existing LBAs, and as a result, we realize the full tax benefit of such increased tax basis (or an increased portion thereof).
Certain changes in control require us to make payments to RTEA, which could exceed our actual cash savings and could require us to provide credit support. If we or CPE Resources undergo a change in control other than a change in control caused by RTEA and we do not otherwise elect to terminate the Tax Receivable Agreement as discussed below, payments to RTEA under the Tax Receivable Agreement will continue on a yearly basis but will be based on an agreed upon set of assumptions. In this case, our assumed cash tax savings, and consequently our payments due under the Tax Receivable Agreement, could exceed our actual cash tax savings each year by material amounts. If we undergo such a change in control and our credit rating is impaired, we will be required to obtain credit support with regard to all remaining payments under the agreement. The change of control provisions may deter a potential sale of our company to a third party and may otherwise make it less likely a third party would enter into a change of control transaction with us.
Certain asset transfers outside the ordinary course of our business may require us to make additional or accelerated payments under the Tax Receivable Agreement. In addition to our obligations to make payments to RTEA with respect to our actual cash tax savings, if CPE Resources sells any asset with a gross value greater than $10 million outside the ordinary course of its business in a wholly or partially taxable transaction, we will be required to make yearly payments to RTEA equal to RTEA's deemed cost of financing its accelerated tax liabilities with respect to such sale, and after such asset sales, we will be required to make certain adjustments to the calculation of our actual cash tax savings for taxable years following sales. These adjustments could result in an acceleration of our obligations under the Tax Receivable Agreement. In addition, our debt instruments contain limitations on CPE Resources' ability to make distributions, which could affect our ability to meet these payment obligations. These limitations on CPE Resources' ability to make distributions may limit our ability to engage in certain taxable asset sales or dispositions outside the ordinary course of our business.
Default under the Tax Receivable Agreement will permit RTEA to accelerate our obligations. If we default on our obligations under the Tax Receivable Agreement (including by reason of insufficient cash distributions from CPE Resources), such default will permit RTEA to enforce its rights under the Tax Receivable Agreement, including by acceleration of our obligations thereunder.
Our ability to achieve benefits from any tax basis increase, and, therefore, the payments expected to be made under the Tax Receivable Agreement, depends upon a number of factors, as discussed above, including the timing and amount of our future income. The U.S. Internal Revenue Service could challenge one or more of our tax positions relevant to the Tax Receivable Agreement and a court could sustain such a challenge. Such a challenge could result in a decrease in our tax benefits, as well as our obligations under the Tax Receivable Agreement. We must obtain RTEA's consent prior to settlement of any such challenge if it may affect RTEA's rights and obligations under the Tax Receivable Agreement.
Our results as a separate, stand-alone public company are significantly different from those portrayed in our pre-IPO financial results.
The historical financial information for all periods prior to our IPO included in this Form 10-K was derived from the consolidated financial statements of Rio Tinto and does not reflect what our financial position, results of operations, cash flows, costs or expenses would have been had we been a separate, stand-alone public company during those periods presented. Rio Tinto did not account for us, and we were not operated, as a separate, stand-alone public company for the historical periods presented prior to our IPO. The historical costs and expenses reflected in our consolidated financial statements for periods prior to our IPO also include allocations of certain general and administrative costs and Rio Tinto's headquarters costs. These expenses are estimates and were based on what we and Rio Tinto considered to be reasonable allocations of the historical costs incurred by Rio Tinto to provide these services required in support of our business.
As a separate, stand-alone public company, our cost structure is different and includes both additional recurring costs and nonrecurring costs. Accordingly, our historical consolidated financial information is not reflective of our financial position, results of operations or cash flows or costs had we been a separate, stand-alone public company during all of the periods presented, and the historical financial information is not a reliable indicator of what our financial position, results of operations or cash flows will be in the future.
Prior to the IPO, our directors and executive officers had potential conflicts of interest with us and your interests as shareholders.
Prior to the IPO, at the time of agreeing to certain matters related to the IPO and IPO Structuring Agreements, Cloud Peak Energy Inc. was an indirect wholly-owned subsidiary of Rio Tinto. As a result, the Cloud Peak Energy Inc. directors at that time owed a fiduciary duty solely to Rio Tinto in its capacity as the sole owner of Cloud Peak Energy Inc. and did not owe a fiduciary duty to our post-IPO stockholders. Keith Bailey, William T. Fox III and Chris Tong, all of whom are current "independent" directors of Cloud Peak Energy Inc. under applicable NYSE rules, were also Cloud Peak Energy Inc. directors prior to the IPO and therefore owed a fiduciary duty to Rio Tinto. Upon the effectiveness of the IPO in November 2009, Rio Tinto's ownership of Cloud Peak Energy Inc. was terminated and, accordingly, Messrs. Bailey, Fox and Tong no longer owed a fiduciary duty to Rio Tinto.
Our agreements with Rio Tinto and its affiliates related to our IPO are likely less favorable to us than similar agreements negotiated between unaffiliated third parties.
We entered into various agreements with Rio Tinto and its affiliates in connection with our IPO which address, among other things, the allocation of assets and liabilities between subsidiaries of Rio Tinto and us, responsibility for the disclosures made in our IPO prospectus and in the offering memorandum used in the senior notes offering, our obligation to provide Rio Tinto financial information needed for its public filings, certain ongoing commercial relationships and our responsibility as the manager of CPE Resources to RTEA and KMS as former non-managing members. CPE Resources has agreed to indemnify Rio Tinto for any losses experienced pursuant to these agreements, in certain instances on a dollar-for-dollar basis and in certain other instances by providing additional indemnification calculated on a dollar-for-dollar basis plus a fraction of a dollar equal to the ownership interest of Rio Tinto and its affiliates in CPE Resources at the time the indemnity is payable to Rio Tinto. Because these agreements were entered into while we were part of Rio Tinto, some of the terms of these agreements are likely less favorable to us than similar agreements negotiated between unaffiliated third parties.
Third parties may seek to hold us responsible for liabilities of Rio Tinto that we did not assume.
Third parties may seek to hold us responsible for liabilities of Rio Tinto that we did not assume in connection with our IPO, including liabilities related to the Jacobs Ranch and Colowyo mines, as well as the uranium mining venture that we do not own. Under certain of the IPO Structuring Agreements, RTA will indemnify us for certain claims and losses relating to these liabilities. If those liabilities are significant and we are ultimately held liable for them, we may not be able to recover the full amount of our losses from RTA.
We are a holding company with no direct operations of our own and depend on distributions from CPE Resources to meet our ongoing obligations.
We are a holding company with no direct operations of our own and have no independent ability to generate revenue. Consequently, our ability to obtain operating funds depends upon distributions from CPE Resources and payments under our management services agreement. Pursuant to the
Management Services Agreement between us and CPE Resources, CPE Resources will make payments to us in the form of a management fee and cost reimbursements to fund our day-to-day operating expenses, such as payroll for our officers. However, if CPE Resources cannot make the payments pursuant to the management services agreement, we may be unable to cover these expenses.
The distribution of cash flows by CPE Resources to us will be subject to statutory restrictions under the Delaware Limited Liability Company Act and contractual restrictions under CPE Resources' debt instruments that may limit the ability of CPE Resources to make distributions. In addition, any distributions and payments of fees or costs will be based upon CPE Resources' financial performance.
As the sole member of CPE Resources, we will incur income taxes on any net taxable income of CPE Resources. Our debt instruments allow CPE Resources to distribute cash in amounts sufficient for us to pay our tax liabilities payable to any governmental entity, and, in the ordinary course of business, our obligations under the Tax Receivable Agreement, if any. To the extent we need funds for any other purpose, and CPE Resources is unable to provide such funds because of limitations in its debt instruments, it could have a material adverse effect on our business, financial condition, results of operations or prospects.
If we are determined to be an investment company, we would become subject to burdensome regulatory requirements and our business activities could be restricted.
We do not believe that we are an "investment company" under the Investment Company Act of 1940, as amended. As managing member of CPE Resources, we control CPE Resources and believe our interest in CPE Resources is neither a "security" nor an "investment security," as those terms are defined in the Investment Company Act. If we were to stop participating in the management of CPE Resources, our interest in CPE Resources could be deemed an "investment security" for purposes of the Investment Company Act. Generally, a company is an "investment company" if it owns investment securities having a value exceeding 40% of the value of its total assets (excluding U.S. government securities and cash items). Our sole material asset is our managing membership interest in CPE Resources. A determination that this interest is an investment security could result in our being considered an investment company under the Investment Company Act. As a result, we would become subject to registration and other burdensome requirements of the Investment Company Act. In addition, the requirements of the Investment Company Act could restrict our business activities, including our ability to issue securities.
We and CPE Resources intend to conduct our operations so that we are not deemed an investment company under the Investment Company Act. However, if anything were to occur that would cause us to be deemed to be an investment company, we would become subject to restrictions imposed by the Investment Company Act. These restrictions, including limitations on our capital structure and our ability to enter into transactions with our affiliates, could make it impractical for us to continue our business as currently conducted and could have a material adverse effect on our financial performance and operations.
Risks Related to Ownership of Our Common Stock
Our common stock has only traded since November 20, 2009 and our stock price could be volatile and could decline for a variety of reasons, resulting in a substantial loss on your investment.
Our common stock has only traded since November 20, 2009. The stock markets generally have experienced extreme volatility, often unrelated to the operating performance of the individual companies whose securities are traded publicly. Broad market fluctuations and general economic conditions may materially adversely affect the trading price of our common stock.
Significant price fluctuations in our common stock could result from a variety of other factors, including, among other things, actual or anticipated fluctuations in our operating results or financial condition, new laws or regulations or new interpretations of existing laws or regulations applicable to our business, sales of our common stock by our shareholders and any other factors described in this "Risk Factors" section of this Form 10-K.
If securities analysts cease coverage about our company and our industry, or if they issue unfavorable commentary about us or our industry or downgrade our common stock, the price of our common stock could decline.
The trading market for our common stock depends in part on the research and reports that third-party securities analysts publish about our company and our industry. One or more analysts could downgrade our stock or issue other negative commentary about our company or our industry. If one or more of these analysts cease coverage of our company, we could lose visibility in the market. The occurrence of one or more of these factors could cause the trading price for our stock to decline.
Future sales of our common stock or other securities convertible into our common stock could cause our stock price to decline.
A decline in the trading price of our common stock due to the occurrence of any future sales of stock might impede our ability to raise capital through the issuance of additional shares of our common stock or other equity securities and may cause you to lose part or all of your investment in our shares of common stock.
Anti-takeover provisions in our charter documents and other aspects of our structure may discourage, delay or prevent a change in control of our company and may adversely affect the trading price of our common stock.
Certain provisions in our amended and restated certificate of incorporation and amended and restated bylaws and other aspects of our structure may discourage, delay or prevent a change in our management or a change in control over us that stockholders may consider favorable. Among other things, our amended and restated certificate of incorporation and amended and restated bylaws:
•provide for a classified board of directors, which may delay the ability of our stockholders to change the membership of a majority of our board of directors;
•authorize the issuance of "blank check" preferred stock that could be issued by our board of directors to thwart a takeover attempt;
•do not provide for cumulative voting;
•provide that vacancies on the board of directors, including newly created directorships, may be filled only by a majority vote of directors then in office;
•limit the calling of special meetings of stockholders;
•provide that stockholders may not act by written consent;
•provide that our directors may be removed only for cause;
•require supermajority voting to effect certain amendments to our certificate of incorporation and our bylaws; and
•require stockholders to provide advance notice of new business proposals and director nominations under specific procedures.
In addition, the LLC Agreement requires that we conduct all our business operations through CPE Resources.
Item 1B.
Item 1B. Unresolved Staff Comments.
None
Item 2.
Item 2. Properties.
See Item 1 "Business-Mining Operations" for specific information about our mining operations.
Coal Reserves
As of December 31, 2010, we controlled approximately 970 million tons of proven and probable coal reserves. All of our proven and probable reserves are classified as steam coal.
The following table summarizes the tonnage of our coal reserves that is classified as proven or probable, and assigned, as well as our property interest, as of December 31, 2010:
(1)Based on our 50% interest in the Decker mine.
(2)Total reflects rounding.
The following table provides the "quality" (sulfur content and average Btu content per pound) of our coal reserves as of December 31, 2010:
(1)Average Btu per pound includes weight of moisture in the coal on an as-sold basis.
(2)All our coal is considered to be compliance coal under the Clean Air Act.
(3)Based on our 50% interest in the Decker mine.
(4)Total reflects rounding.
We also control certain coal deposits that are contiguous to or near our primary reserve bases. The tons in these deposits are classified as non-reserve coal deposits and are not included in our reported reserves. These non-reserve coal deposits are as follows:
Antelope Mine: 80 million tons
Cordero Rojo Mine: 176 million tons
Our reserve and non-reserve coal deposit estimates as of December 31, 2010 were prepared by our staff of geologists and engineers, who has extensive experience in PRB coal. These individuals are responsible for collecting and analyzing geologic data within and adjacent to leases controlled by us.
A review of our 2010 resources and reserves assessments was completed in January 2011 by John T. Boyd Company, mining and geological consultants, and covered our reserves as of December 31, 2010. The results verified our reserve estimates. Our reserve estimates of approximately 970 million tons for the year ended December 31, 2010 were confirmed by John T. Boyd Company, as well as approximately 256 million tons of non-reserve coal deposits we held as of December 31, 2010.
Our coal reserve estimates are based on data obtained from our drilling activities and other available geologic data. All of our reserves are assigned, associated with our active coal properties, and incorporated in detailed mine plans. Estimates of our reserves are based on more than 7,500 drill holes. Our proven reserves have a typical drill hole spacing of 1,500 feet or less, and our probable reserves have a typical drill hole spacing of 2,500 feet or less.
Along with the geological data we assemble for our coal reserve estimates, our staff of geologists and engineers also analyzes the economic data such as cost of production, projected sales price and other data concerning permitting and advances in mining technology. Various factors and assumptions are utilized in estimating coal reserves, including assumptions concerning future coal prices and operating costs. These estimates are periodically updated to reflect past coal production and other geologic or mining data. Acquisitions or sales of coal properties will also change these estimates. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam. We maintain reserve information in secure computerized databases, as well as in hard copy.
Reserve Acquisition Process
Since our inception, we have focused on growth through, among other things, the federal competitive leasing process, including the LBA process, and we continue to identify federal coal leasing opportunities. For example, in 2007 we acquired 107.5 million tons of reserves in an LBA for our Spring Creek mine. In addition, in 2008 we acquired 161 million tons of reserves in an LBA for our Cordero Rojo mine. Similarly, in May 2009 we acquired an additional 48 million tons of reserves with the North Maysdorf LBA tract, for our Cordero Rojo mine.
We acquire a significant portion of our coal through the LBA process, and as a result, substantially all of our coal is held under federal leases. Under this process, before a mining company can obtain new federal coal, the company must nominate a coal tract for lease and then win the lease through a competitive bidding process. The LBA process can last anywhere from two to five years from the time the coal tract is nominated to the time a final bid is accepted by the BLM. After the LBA is awarded, the company then conducts the necessary testing to determine what amount can be classified as reserves and begins the process to permit the coal for mining, which generally takes another two to five years. Third-party legal challenges, such as legal challenges filed in 2010 against the BLM and the Secretary of the Interior by environmental groups with respect to the LBA process in the PRB and the West Antelope II LBA, may result in delays and other adverse impacts on the LBA process.
To initiate the LBA process, companies wanting to acquire additional coal must file an application with the BLM's state office indicating interest in a specific coal tract. The BLM reviews the initial application to determine whether the application conforms to existing land-use plans for that particular tract of land and whether the application would provide for maximum coal recovery. The application is further reviewed by a regional coal team at a public meeting. Based on a review of the available information and public comment, the regional coal team will make a recommendation to the BLM whether to continue, modify or reject the application.
The BLM also allows for small tracts of coal to be acquired through a leasing process known as a Lease by Modification, or LBM. An LBM is a non-competitive leasing process and is used in circumstances where a lessee is seeking to modify an existing federal coal lease by adding less than 960 acres in a configuration that is deemed non-competitive to other coal operators. In June 2010, we entered into a modified coal lease with the BLM through the LBM process to add approximately 48 million tons of proven and probable reserves to one of the Spring Creek mine's existing federal coal leases.
If the BLM determines to continue the application, the company that submitted the application will pay for a BLM-directed environmental analysis or an EIS to be completed. This analysis or impact statement is subject to publication and public comment. The BLM may consult with other government agencies during this process, including state and federal agencies, surface management agencies, Native American tribes or bands, the U.S. Department of Justice or others as needed. The public comment period for an analysis or impact statement typically occurs over a 60-day period.
After the environmental analysis or EIS has been issued and a recommendation has been published that supports the lease sale of the LBA tract, the BLM schedules a public competitive lease sale. The BLM prepares an internal estimate of the fair market value of the coal that is based on its economic analysis and comparable sales analysis. Prior to the lease sale, companies interested in acquiring the lease must send sealed bids to the BLM. The bid amounts for the lease are payable in five annual installments, with the first 20% installment due when the mining operator submits its initial bid for an LBA. Before the lease is approved by the BLM, the company must first furnish to the BLM an initial rental payment for the first year of rent along with either a bond for the next 20% annual installment payment for the bid amount, or an application for history of timely payment, in which case the BLM may waive the bond requirement if the company successfully meets all the qualifications of a timely payor. The bids are opened at the lease sale. If the BLM decides to grant a lease, the lease is awarded to the company that submitted the highest total bid meeting or exceeding the BLM's fair market value estimate, which is not published. The BLM, however, is not required to grant a lease even if it determines that a bid meeting or exceeding the fair market value of the coal has been submitted. The winning bidder must also submit a report setting forth the nature and extent of its coal holdings to the U.S. Department of Justice for a 30-day antitrust review of the lease. If the successful bidder was not the initial applicant, the BLM will refund the initial applicant certain fees it paid in connection with the application process, for example the fees associated with the environmental analysis or EIS, and the winning bidder will bear those costs. Coal won through the LBA process and subject to federal leases are administered by the U.S. Department of Interior under the Federal Coal Leasing Amendment Act of 1976. In addition, we occasionally add small coal tracts adjacent to our existing LBAs through an agreed upon lease modification with the BLM. Once the BLM has issued a lease, the company must next complete the permitting process before it can mine the coal. See "-Environmental and Other Regulatory Matters-Mining Permits and Approvals."
The federal coal leasing process is designed to be a public process, giving stakeholders and other interested parties opportunities to comment on the BLM's proposed and final actions and allow third-party comments. Because of this, third parties, including non-governmental organizations, can challenge the BLM's actions, which may delay the leasing process. If these challenges prove successful or are litigated for a prolonged period of time, a coal company's ability to bid on or acquire a new coal lease could be significantly delayed, or could cause the BLM to not offer a lease for bid at all. In 2010, environmental organizations filed legal challenges against the BLM's findings on the final EIS and other matters associated with the West Antelope II LBA, which was nominated by our Antelope mine. These challenges have created some uncertainty with respect to the timing of the LBA bid and lease acquisition and may ultimately delay the leasing process or prevent mining operations. Even after a lease has been issued and a successful bidder has paid installment money to the BLM, legal challenges may still seek to delay or prevent mining operations. It is possible that subsequent EISs for other mines
in the PRB currently underway but not yet final could be similarly challenged. There also exists the possibility of similar challenges to the permitting and licensing process, which is also a public process designed to allow public comments.
Each of our federal coal leases has an initial term of 20 years, renewable for subsequent 10-year periods and for so long thereafter as coal is produced in commercial quantities. The lease requires diligent development within the first ten years of the lease award with a required coal extraction of 1% of the total coal under the lease by the end of that 10-year period. At the end of the 10-year development period, the lessee is required to maintain continuous operations, as defined in the applicable leasing regulations. In certain cases, a lessee may combine contiguous leases into a logical mining unit, or LMU. This allows the production of coal from any of the leases within the LMU to be used to meet the continuous operation requirements for the entire LMU. We currently have an LMU for our Antelope mine. We pay to the federal government an annual rent of $3.00 per acre and production royalties of 12.5% of gross revenues on surface mined coal. The federal government remits approximately 50% of the production royalty payments to the state after deducting administrative expenses. Some of our mines are also subject to coal leases with the states of Montana or Wyoming, as applicable, and have different terms and conditions that we must adhere to in a similar way to our federal leases. Under these federal and state leases, if the leased coal is not diligently developed during the initial 10-year development period or if certain other terms of the leases are not complied with, including the requirement to produce a minimum quantity of coal or pay a minimum production royalty, if applicable, the BLM or the applicable state regulatory agency can terminate the lease prior to the expiration of its term.
Most of the coal we lease from the United States comes from "split estate" lands in which one party, typically the federal government, owns the coal and a private party owns the surface. In order to mine the coal we acquire through the LBA process, we must also acquire rights to mine from the owners of the surface lands overlying the coal. Certain federal regulations provide a specific class of surface owners, Qualified Surface Owners, or QSOs, with the ability to prohibit the BLM from leasing its coal. For example, in connection with a pending LBA that we nominated for our Cordero Rojo mine, the BLM has indicated that certain surface owners satisfy the regulatory definition of QSO. If the land overlying a coal tract is owned by a QSO, federal laws prohibit us from leasing the coal tract without first securing surface rights to the land, or purchasing the surface rights from the QSO, which would allow us to conduct our mining operations. Furthermore, the state permitting process requires us to demonstrate surface owner consent for split estate lands before the state will issue a permit to mine coal. This consent is separate from the QSO consent required before leasing federal coal. The right of QSOs and certain other surface owners allows them to exercise significant influence over negotiations and prices to acquire surface rights and can delay the LBA or permitting processes or ultimately prevent the acquisition of the LBA or permit over that land entirely. There are QSOs that own land adjacent to or near our existing mines that may be attractive acquisition candidates for us. Typically, we seek to purchase the land overlying our coal or enter into option agreements granting us an option to purchase the land upon acquiring an LBA. In some instances, however, we enter into separate lease arrangements with surface owners allowing us to conduct our mining operations on the land. We own substantially all of the land over our reserves.
We also enter into surface leases with other third parties from time to time. The majority of these third-party leases have a term that continues until the exhaustion of the "mineable and merchantable" coal in the lease area. Some of our leases extend for a specific number of years rather than to the exhaustion of the particular mine's reserves, but in all these cases, we believe that the term of years will allow the recoverable reserve to be fully extracted in accordance with our projected mine plan. Consistent with industry practice, we conduct only limited investigations of title to our coal properties prior to leasing. Title to properties leased from private third parties is not usually fully verified until we
make a commitment to develop a property, which may not occur until we have obtained the necessary permits and completed exploration of the property.
Office Space
Our corporate headquarters is located in Gillette, Wyoming, where we own approximately 32,000 square feet of office space. In addition, we lease approximately 7,500 square feet of additional office space in Gillette, Wyoming, under two annual leases expiring on June 30, 2011 and May 31, 2012, and we lease approximately 28,100 square feet of office space in Broomfield, Colorado under a lease that expires in February 2021. As of December 31, 2010, all of our long-lived assets were located in the U.S. See Note 18 of Notes to Consolidated Financial Statements in Item 8.
Item 3.
Item 3. Legal Proceedings.
MMS Litigation-Decker Mine
The Minerals Management Service, or MMS, a federal agency with responsibility for collecting royalties on coal produced from federal coal leases, issued two disputed assessments against Decker Coal Company: one for coal produced from 1986-1992, and the other for coal produced from 1993-2001. Both assessments concern coal sold by Decker to Big Horn Coal Company, or Big Horn, and Black Butte Coal Company, or Black Butte, and in turn resold by those entities to Commonwealth Edison Company to satisfy requirements under long-term contracts between those entities and Commonwealth Edison. The MMS maintained that Decker's royalties should not be based on the prices at which Decker actually sold coal to Big Horn and Black Butte because MMS did not believe those prices represented the results of arm's length negotiation. MMS based this conclusion on the facts that those entities were both affiliates of KCP, Inc., formerly known as Kiewit Coal Properties, Inc., which is also a 50% owner of Decker, and that the sales were contingent on Big Horn's and Black Butte's ability to resell the coal to Commonwealth Edison, which did not leave Big Horn and Black Butte at market risk. Instead, the MMS assessed Decker's royalties based on the higher prices set under Big Horn's and Black Butte's separate long-term contracts with Commonwealth Edison.
With respect to the period 1986-1992, the MMS assessment did not contain a specific dollar amount. Decker appealed the assessment through the administrative process with the MMS and that appeal was unsuccessful. A further appeal was filed before the United States District Court for the District of Montana. In March 2009, the District Court set aside the MMS assessment and entered judgment for Decker ("Decker I"). The MMS did not appeal the ruling.
With respect to the period 1993-2001, the MMS assessed approximately $7.5 million plus interest, which was estimated to be approximately $11 million inclusive of interest. Decker appealed the MMS assessment through the administrative process with the MMS and that appeal was unsuccessful. A further appeal was filed before the United States District Court for the District of Montana. In February 2010, the District Court vacated the administrative order from the Interior Board of Land Appeals affirming the MMS assessment. The District Court remanded the case to the MMS for further review and noted that the remand would not unduly prejudice Decker in light of the District Court's opinion in Decker I. There is no MMS assessment currently pending against Decker for the 1993 - 2001 period.
We have not accrued a liability in our consolidated financial statements with respect to this matter as any potential losses are not considered to be probable and reasonably estimable. If the MMS issues a new assessment for the 1993 - 2001 period, Decker believes it will have substantive challenges to any such assessment in light of the District Court's decision in Decker I. Decker also believes that it has contractual price escalation protection from any increased assessments for 1993-2001; and that, in addition, Commonwealth Edison has indemnified Black Butte with respect to the 1993-2001 assessment,
and that in furtherance of that obligation, Commonwealth Edison or its parent company, Exelon Generation, Inc., has therefore agreed to indemnify Decker directly for such matters. If a new assessment is issued by the MMS for the 1993 - 2001 period and is upheld and the indemnities and/or price protections were ultimately not available to Decker, the resulting Decker liability could be material. As a result of our 50% ownership interest in Decker, our financial results could in turn be materially adversely affected. We consider Decker's conclusions to be reasonable; however, we have not relied upon Decker's conclusions in reaching our decision that any potential losses are not considered probable and reasonably estimable.
Caballo Coal Company Litigation-Spring Creek
In September 2009, Caballo Coal Company ("Caballo"), a subsidiary of Peabody Energy Corporation, commenced an action in Wyoming state court against Spring Creek Coal Company ("Spring Creek"), our wholly-owned subsidiary, asserting that Spring Creek repudiated its allegedly remaining obligation under a 1987 agreement to purchase an additional approximately 1.6 million tons of coal, for which it seeks unspecified damages. Spring Creek believes that it has meritorious defenses to the claim, including that Caballo breached the agreement by failing to make required deliveries in 2006 and 2007. Spring Creek also believes that it has meritorious counterclaims against Caballo. We have not accrued a liability in our consolidated financial statements with respect to this matter as any potential losses are not considered to be probable and reasonably estimable. If, however, the case was determined in an adverse manner to us, the payment of any judgment could be material to our results of operations.
Other Legal Proceedings
We are involved in other legal proceedings arising in the ordinary course of business and may become involved in additional proceedings from time to time. We believe that there are no other legal proceedings pending that are likely to have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Nevertheless, we cannot predict the impact of future developments affecting our claims and lawsuits, and any resolution of a claim or lawsuit or an accrual within a particular fiscal period may adversely impact our results of operations for that period. In addition to claims and lawsuits against us, our LBAs, permits and other industry regulatory processes and approvals may also be subject to legal challenges that may adversely impact our mining operations and results. For example, the West Antelope II LBA, which we have nominated for lease with the Bureau of Land Management, is subject to pending legal challenges filed in 2010 against the Bureau of Land Management and the Secretary of the Interior by environmental organizations.
Item 4.
Item 4. Reserved.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
Our common stock, $0.01 par value, has traded on the New York Stock Exchange under the symbol "CLD" since November 20, 2009. Prior to November 20, 2009, there was no public market for our common stock.
The following table sets forth the high and low closing sales prices of our common stock, as reported by the NYSE, for each of the periods listed.
As of the close of business on January 31, 2011, we have 1,446 holders of record of our common stock.
Dividend Policy
We have not and we do not anticipate that we will pay cash dividends on our common stock in the near term. Any determination to pay dividends to holders of our common stock in the future will be at the discretion of our Board of Directors and will depend on many factors, including our financial condition; results of operations; general business conditions; contractual restrictions, including those under our debt instruments; capital requirements; business prospects; restrictions on the payment of dividends under Delaware Law; and any other factors our Board of Directors deems relevant. See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations-Senior Unsecured Notes and-Senior Secured Revolving Credit Facility."
Stock Performance Graph
The following performance graph compares the cumulative total return on our common stock with the cumulative total return of the following indices: (i) the Standard & Poor's ("S&P") MidCap 400 stock index and (ii) the Custom Composite Index comprised of Alpha Natural Resources, Inc., Arch Coal, Inc., CONSOL Energy, Inc., Massey Energy Company and Peabody Energy Corp. The graph assumes that you invested $100 in our common stock and in each index at the closing price on November 20, 2009, that all dividends were reinvested and that you continued to hold your investment through December 31, 2010. In January 2011, Alpha Natural Resources, Inc. and Massey Energy Company announced they signed a definitive agreement under which Alpha Natural Resources will acquire all outstanding shares of Massey Energy Company common stock, subject to customary closing conditions, including stockholder approval of both companies.
These indices are included for comparative purposes only and do not necessarily reflect management's opinion that such indices are an appropriate measure of the relative performance of the stock involved, and are not intended to forecast or be indicative of possible future performance of our common stock.
COMPARISON OF CUMULATIVE TOTAL RETURN
ASSUMES $100 INVESTED ON NOV. 20, 2009
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDING DEC. 31, 2010
In accordance with SEC rules, the information contained in the Stock Performance Graph above shall not be deemed to be "soliciting material," or to be "filed" with the SEC or subject to the SEC's Regulation 14A or 14C, other than as provided under Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended, except to the extent that we specifically request that the information be treated as soliciting material or specifically incorporate it by reference into a document filed under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended.
Item 6.
Item 6. Selected Financial Data.
The following tables set forth our selected consolidated financial and other data on a historical basis. The information below should be read in conjunction with Item 7
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
This Item 7 is intended to help the reader understand our results of operations and financial condition. This discussion should be read in conjunction with our consolidated financial statements in Item 8, the section entitled "Cautionary Note Regarding Forward-Looking Statements" and Item 1A "Risk Factors."
Overview
We are the third largest producer of coal in the U.S. and in the PRB based on 2010 coal production. We operate some of the safest mines in the coal industry. For 2010, MSHA data for employee injuries showed our mines had the lowest employee all injury incident rate among the five largest U.S. coal producing companies. We operate solely in the PRB, the lowest cost of the major coal producing regions in the U.S., and operate two of the four largest coal mines in the region and in the U.S. Our operations include three wholly-owned surface coal mines, two of which, the Antelope Coal mine and the Cordero Rojo mine, are in Wyoming and one of which, the Spring Creek Coal mine, is in Montana. We also own a 50% non-operating interest in a fourth surface coal mine in Montana, the Decker mine. We produce sub-bituminous steam coal with low sulfur content and sell our coal primarily to domestic electric utilities.
Initial Public Offering, Related IPO Structuring Transactions, and Secondary Offering
Prior to our IPO and the related structuring transactions, CPE Resources was a wholly-owned subsidiary of RTEA, which is our predecessor for financial reporting purposes. See "Initial Public Offering, Related IPO Structuring Transactions, and Secondary Offering" in Note 2 of Notes to Consolidated Financial Statements in Item 8. On November 19, 2009, Cloud Peak Energy Inc. acquired from RTEA 51% of the common membership units in CPE Resources in exchange for a promissory note, which was repaid on November 25, 2009 using the proceeds from our IPO, and became the managing member of CPE Resources. As a result of these transactions, Cloud Peak Energy Inc. became a publicly owned holding company with a controlling interest in CPE Resources and its subsidiaries.
On December 15, 2010, Cloud Peak Energy Inc. priced the Secondary Offering of 29,400,000 shares of its common stock. In connection with the Secondary Offering, we exchanged 29,400,000 shares of common stock for the common membership units of CPE Resources held by Rio Tinto and completed the Secondary Offering, resulting in a divestiture of 100% of Rio Tinto's holdings in CPE Resources. As a result of this transaction, CPE Resources is now a wholly-owned subsidiary of Cloud Peak Energy Inc. In addition, the elimination of Rio Tinto as a member results in the elimination of noncontrolling interest in our consolidated balance sheet during the period. The statement of operations for the year ended December 31, 2010 will present the portion of income attributable to the noncontrolling interest through the date of the Secondary Offering and no income will be attributable to the noncontrolling interest in future periods. This transaction also resulted in an increase to the undiscounted future liability under the Tax Receivable Agreement of $123.6 million and an increase to our deferred income taxes of $93.6 million net of valuation allowances.
For all periods presented, our historical consolidated financial statements include the accounts of CPE Resources and its subsidiaries. For periods ending after July 31, 2008 (the date Cloud Peak Energy Inc. was incorporated), our consolidated financial statements include the accounts of Cloud Peak Energy Inc.; however, Cloud Peak Energy Inc. did not have any business operations or material transactions prior to November 19, 2009. For periods prior to November 20, 2009, our consolidated financial statements also include the accounts of RTEA, which was the parent company of CPE Resources prior to our IPO structuring transactions. As a result of our IPO structuring transactions, our consolidated financial statements reflect Cloud Peak Energy Inc. as the parent company and no longer include the accounts of RTEA, our former parent company. For periods between November 20, 2009 (the date of the IPO) and December 15, 2010 (the date of the Secondary Offering), Rio Tinto's ownership interest in CPE Resources is reported as a noncontrolling interest in our consolidated financial statements.
The IPO structuring transactions and related agreements were entered into by Cloud Peak Energy Inc., CPE Resources, RTEA and other Rio Tinto affiliates while they were under common control by Rio Tinto. In accordance with U.S. GAAP we did not adjust the historical financial reporting carrying amounts of our assets and liabilities in connection with the IPO structuring transactions or the Secondary Offering.
Our IPO and the related structuring transactions had significant effects on the comparability of our 2009 and 2010 consolidated financial statements with our consolidated financial statements for prior annual periods. These effects include the following:
•Related Party Transactions: Prior to our IPO, our consolidated balance sheets included substantial amounts due from or to related parties, reflecting balances arising from services that we received from Rio Tinto and cash transfers pursuant to a cash management arrangement with Rio Tinto. In connection with our IPO, substantially all amounts due from or to Rio Tinto were cancelled and converted to equity. At December 31, 2010 and 2009, amounts due from or to related parties primarily reflect certain transitional arrangements with Rio Tinto that were concluded in 2010.
•Financing and Cash Management: As a consequence of our participation in the Rio Tinto cash management arrangement prior to our IPO, we did not enter into any significant financing arrangements directly with third parties and we did not maintain any significant cash balances, except for cash balances held by our Decker joint venture which we consolidate on a pro rata basis. In connection with our IPO, we received cash proceeds from the issuance of senior notes and entered into a revolving credit facility with third-party lenders. We no longer participate in Rio Tinto's cash management arrangement and we retained a substantial portion of the senior notes proceeds in order to fund a portion of our anticipated future operating, financing and capital expenditure requirements. As a result of these transactions, our December 31, 2010 and
consolidated balance sheets reflect significant amounts of cash and cash equivalents, restricted cash and long-term debt, which were not reflected in our balance sheets at prior reporting dates. In addition, our operating results for the period following our IPO reflect interest expense related to our new debt financing arrangements.
•Cost Structure: Prior to our IPO, we prepared our financial statements on a carve-out basis. Accordingly, our pre-IPO operating results included allocations of general and administrative expenses incurred on our behalf by Rio Tinto affiliates. In 2008 and 2009, our pre-IPO operating results also reflected significant expenses that were incurred in connection with Rio Tinto's divestiture of our business. Following our IPO, our operating results are no longer affected by Rio Tinto expense allocations and divestiture expenses. However, during the second half of 2009 and through 2010, we incurred recurring and nonrecurring expenses that are necessary to operate effectively as a stand-alone public company.
•Income Taxes: Prior to our IPO, our taxable income was included in Rio Tinto America's consolidated federal income tax return and we recognized income tax expense in our carve-out consolidated financial statements on a stand-alone, separate-return basis. As a result of our IPO and related structuring transactions, we recognize income taxes in our consolidated financial statements based on pre-tax income that we expect to report in Cloud Peak Energy Inc.'s federal income tax return, which consists primarily of our interest (51.7% to the date of the Secondary Offering; 100% as of December 31, 2010) in CPE Resources' pre-tax income. We did not recognize any income taxes that Rio Tinto America may be subject to in connection with its noncontrolling interest (48.3% to the date of the Secondary Offering; 0% as of December 31, 2010) in CPE Resources, which is generally not a tax-paying entity. During the periods that we did not recognize income taxes on the noncontrolling interest share of CPE Resources' pre-tax income (i.e. between our IPO and the Secondary Offering), our effective income tax rate (i.e., total income tax expense as a percentage of total pre-tax income) was lower.
•Deferred Taxes: In connection with our IPO and structuring transactions, we eliminated RTEA's deferred income tax accounts from our consolidated balance sheet and we recorded deferred income taxes related to the difference between the financial reporting carrying amount and the tax basis of Cloud Peak Energy Inc.'s investment in CPE Resources. The deferred taxes that we recorded reflect an increase in tax basis that resulted from our IPO structuring transactions and apply only to the 51.0% interest in CPE Resources that was acquired by Cloud Peak Energy Inc. on November 19, 2009. The deferred taxes that we eliminated did not reflect the increase in tax basis, but applied to 100% of the assets and liabilities of CPE Resources, based on RTEA's prior 100% ownership of CPE Resources. In connection with the Secondary Offering, we recorded additional deferred income taxes related to the difference between the financial reporting carrying amount and the tax basis of Cloud Peak Energy Inc.'s additional investment in CPE Resources.
•Tax Receivable Agreement: In connection with our IPO, Cloud Peak Energy Inc. entered into a Tax Receivable Agreement with RTEA and recognized a liability for the undiscounted amounts that we estimate will be paid to RTEA under this agreement. The amounts to be paid will be determined based on a calculation of future income tax savings that we actually realize as a result of the tax basis increase that resulted from our IPO structuring transactions. Periodically, we will adjust the estimated liability to reflect an updated forecast of our future taxable income and these adjustments will be reflected in our operating results. The assumptions reflected in our estimates involve significant judgment and are subject to substantial uncertainty about future events. Changes in these estimates may have material and unpredictable effects on our future operating results. In connection with the Secondary Offering, we have an additional tax basis increase, resulting in an increased tax agreement liability.
•Noncontrolling Interest: Prior to our IPO and related structuring transactions, our consolidated subsidiaries, including CPE Resources, were wholly owned by RTEA, except for Decker, which is proportionately consolidated as discussed below. As a result of our IPO, the carrying amount of the noncontrolling interest and the portion of our net income that is attributable to the noncontrolling interest was not equal to 48.3% of consolidated equity or of our consolidated net income due to the effects of income taxes and related agreements that pertain solely to Cloud Peak Energy Inc.
The portion of our net income that is attributable to the noncontrolling interest will reflect Rio Tinto's ownership in CPE Resources through the Secondary Offering.
The following unaudited pro forma condensed consolidated results of operations have been prepared as if the Secondary Offering had occurred as of January 1, 2010. The pro forma results are not necessarily indicative of the actual results that would have occurred had the Secondary Offering been in effect for the period presented, nor are they necessarily indicative of the results that may be obtained in the future.
Pro forma adjustments primarily include the impact of the elimination of RTEA's noncontrolling interest and the additional income tax expense that results from the attribution of additional CPE Resources income to Cloud Peak Energy Inc.'s controlling interest in CPE Resources. Additionally, the basic and diluted weighted-average shares outstanding reflect the additional 29,400,000 shares offered in the Secondary Offering.
Discontinued Operations
Our historical consolidated financial statements include discontinued operations related to assets that were transferred or sold prior to our IPO and related structuring transactions:
•RTEA transferred its interests in the Colowyo mine, a coal mine in Colorado and the uranium mining venture to Rio Tinto America on October 7, 2008, and those interests were not contributed to CPE Resources.
•In March 2009, CPE Resources entered into an agreement to sell its ownership interest in the Jacobs Ranch mine, a coal mine in Wyoming, to Arch Coal, Inc. This transaction closed on October 1, 2009 and the proceeds from this sale were distributed to Rio Tinto America.
The assets, liabilities and results of operations of the Jacobs Ranch mine, the Colowyo mine, and the uranium mining venture are presented as discontinued operations in our historical consolidated financial statements. Consequently, the discussion of our results of operations below focuses on continuing operations as reported in our historical consolidated financial statements. Any forward-looking statements exclude the discontinued operations.
Decker Mine
We hold a 50% non-operating interest in the Decker mine in Montana through a joint-venture agreement. Under the terms of our joint-venture agreement, a third-party mine operator manages the day-to-day operations of the Decker mine. We account for our pro-rata share of assets and liabilities in our undivided interest in the joint venture using the proportionate consolidation method, whereby our share of assets, liabilities, revenues and expenses are included in the appropriate classification in our consolidated financial statements.
Core Business Operations
As of December 31, 2010, we controlled approximately 970 million tons of proven and probable coal reserves. For the year ended December 31, 2010, we produced 95.3 million tons of coal and sold 96.9 million tons of coal.
Our key business drivers include the following:
•the volume of coal produced and shipped domestically and internationally;
•the price for which we sell our coal;
•the costs of mining, including labor, repairs and maintenance, fuel, explosives, depreciation of capital equipment, depletion of coal leases and regulatory compliance; and
•capital expenditures to acquire property, plant and equipment.
The volume of coal that we sell and deliver in any given year is driven by the amount of global and domestic demand for electric power. Demand for electric power may be affected by many factors including weather patterns, environmental and legal challenges, political influences, international and domestic economic conditions, and other factors discussed in this Item 7 and in Item 1A of this Form 10-K.
The price at which we sell our coal is a function of the demand relative to the supply for coal, domestically and internationally. As a region's demand increases, prices are also subject to increase, which improves the viability of transporting our coal to a more diverse customer base. We typically enter into longer term contracts with our customers which helps mitigate the risks associated with any imbalance in supply and demand. In addition, international demand has increased, enabling us to increase exports of coal.
We typically seek to enter into the year with expected production fully sold; however, as a result of our remaining unsold and index priced position for 2011 through 2012, we believe we are well positioned to benefit from continued near-term demand and pricing. If, however, the U.S. and international coal markets return to the depressed levels experienced in 2009, our results could be adversely affected.
In line with the worldwide mining industry, we have experienced increased operating costs for mining equipment, diesel fuel and supplies, and employee wages and salaries. Changes in the cost of commodities related to our production process, such as diesel fuel, will result in changes in the cost of coal production. We have not entered into any hedging or other arrangements to reduce the volatility in the price of commodities used for our operations, although we may do so in the future. As is common in the PRB, coal seams at our existing mines naturally deepen at a gradient of approximately 2% to 3%. Strip ratios have a direct correlation with our costs.
Should the costs of acquiring future federal coal leases and associated surface rights increase, our depletion costs will also increase.
Global Climate Change
Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S. or some of its states or by other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. Additionally, the creation and issuance of subsidies designed to encourage use of alternative energy sources could decrease the demand of coal as an energy source. The potential financial impact on us of future laws, regulations or subsidies will depend upon the degree to which electricity generators diminish their reliance on coal as a fuel source as a result of the laws, regulations or subsidies. That, in turn, will depend on a number of factors, including the appeal and design of the subsidies being offered, the specific requirements imposed by any such laws or regulations, the time periods over which those laws or regulations would be phased in and the state of commercial development and deployment of carbon capture and storage technologies. In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws or regulations may have on our results of operations, financial condition or cash flows. See Item 1, "Business-Environmental and Other Regulatory Matters-Climate Change" and Item 1A, "Risk Factors" for additional discussion regarding how climate change and other environmental regulatory matters impact our business.
Results of Operations
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Domestic shipments from our owned and operated mines increased from 89.3 million tons in 2009 to 90.4 million tons in 2010 while shipments to Asian export customers supplied by our Spring Creek mine increased from 1.6 million tons to 3.3 million tons resulting in total shipments increasing from 90.9 million tons to 93.7 million tons. Deliveries to domestic customers increased due to improved economic conditions and weather patterns leading to higher demand for coal-fired electricity. Export deliveries increased due to strengthening international demand for thermal coal.
Total 2010 shipments including our share of the Decker mine and broker sales decreased from 103.3 million tons in 2009 to 96.9 million tons in 2010. This decrease is primarily due to the expiration of our significant broker sales contract in early 2010. During 2009 and the beginning of 2010, we had one significant broker sales contract under which our subsidiary, Spring Creek Coal LLC, sold coal to a wholesale power generation company. The contract expired following final deliveries made under the contract in the first quarter of 2010, and the related contract rights intangible asset has been fully amortized. This broker sales contract contributed $140.4 million and $13.7 million of revenues for the years ended December 31, 2009 and 2010, respectively. Income before tax related to this contract was $46.3 million and $5.0 million for those same periods, respectively, which is net of related expenses, including amortization of an intangible asset for the related contract rights of $28.7 million and $3.2 million, respectively.
Additionally in 2010, we continued to focus on our cost management efforts, which resulted in reducing employee overtime, and optimizing repairs and maintenance expense. For our owned and operated mines, the weighted average cost of diesel fuel was $2.50 per gallon for the year ended December 31, 2010, compared to $1.87 per gallon for the year ended December 31, 2009. Diesel fuel and lubricant expenses represented 9.2% and 7.8% of cost of coal production at our owned and operated mines for the year ended December 31, 2010 and 2009, respectively.
Revenues
The following table presents revenues for the years ended December 31, 2010 and 2009 (in millions):
The increase in revenue from our owned and operated mines reflects a 4.5% increase in the average price per ton of coal sold, from $11.79 in 2009 to $12.32 in 2010, and a 3.1% increase in shipments, from 90.9 million tons in 2009 to 93.7 million in 2010.
The increase in average price per ton sold reflects the strong demand for PRB coal due to prevailing economic and industry conditions at the time we entered into the related coal supply contracts.
Other revenues consist primarily of our share of revenues from coal produced at the Decker mine, broker coal sales and billings for transportation and delivery services. Our share of revenues from coal produced at the Decker mine decreased reflecting a decline in shipments partially offset by higher average price per ton. Broker coal sales reduced following the expiration of our significant contract that expired in the first quarter of 2010. Revenues from transportation and delivery services increased, as a result of a higher volume of coal sold on a delivered basis, including export sales with delivered pricing terms that include rail and port charges, where we arranged and paid for the freight costs and charged our customers on a cost-plus basis for providing this service.
Cost of Product Sold
The following table presents cost of product sold for the years ended December 31, 2010 and 2009 (in millions):
The increase in costs for our owned and operated mines reflects a 3.1% increase in tons shipped from our mines, and a 7.9% increase in the cost per ton of coal produced, from $7.94 in 2009 to $8.57 in 2010. The increase in the cost per ton of coal produced is primarily the result of a 9.2% per ton increase in royalties and production taxes, which reflects the higher average sales prices realized on our 2010 coal shipments as well as updates to estimates for non-income based taxes. Excluding royalties and production taxes, the cost per ton of coal produced increased from $4.53 to $4.83. The increase in the cost per ton of coal produced is primarily the result of increases in costs related to the price of diesel fuel and lubricants, and a higher strip ratio in 2010 compared to 2009 as our mines move into deeper mining areas.
The cost of coal produced by the Decker mine decreased $3.0 million in 2010, reflecting lower production volumes partially offset by higher unit production costs. In addition, the cost of purchased
coal decreased $86.7 million, primarily as a result of decreases of $64.7 million related to our significant broker sales contract that expired in 2010 and $20.0 million for other broker sales of purchased coal. The decreases in coal purchased related to our significant broker sales contract and other broker transactions are consistent with the related decreases in broker sales revenues in 2010. These decreases are partially offset by an increase in international exports in 2010, which resulted in an increase in freight and handling costs.
Operating Income
The following table presents operating income for the years ended December 31, 2010 and 2009 (in millions):
Operating income was affected by the following factors in addition to those discussed above:
•A decrease in amortization expense of $25.5 million, which is attributable to the expiration of the significant broker contract in the first quarter of 2010.
•A decrease in selling, general, and administrative costs primarily due to costs incurred in 2009 associated with our IPO that were not incurred in 2010, offset by the increased costs to operate as a stand-alone public entity and execute the Secondary Offering.
Total Other Expense
The following table presents total other expense for the years ended December 31, 2010 and 2009 (in millions):
*Change from prior period is not a relevant percentage
Total other expense increased due to an increase in interest expense on our $600 million of Senior Notes, which were outstanding for the full year in 2010 compared to approximately one month in 2009. Additionally, during the third quarter, we completed our annual update of our most recent operating plans and the resulting projected estimated future taxable income. This resulted in an increase in the estimated liability due to Rio Tinto under the Tax Receivable Agreement, resulting in a $19.7 million charge to non-operating income. See Note 13 of Notes to Consolidated Financial Statements in Item 8.
Income Tax Provision
The following table presents our income tax provision for the years ended December 31, 2010 and 2009 (in millions):
The effective income tax rate decreased to 21.9% for the year ended December 31, 2010 from 27.4% for the year ended December 31, 2009. The decrease is primarily attributable to RTEA's former non-controlling interest for which we did not accrue taxes, offset by the effect of the revaluation of our deferred tax assets as a result of the update to the Tax Receivable Agreement liability. The adjustment to the effective tax rate for the post-Secondary Offering period in 2010 to account for pretax income attributable to the controlling interest increased our effective tax rate by approximately 0.3%. See Note 13 of Notes to Consolidated Financial Statements in Item 8.
Discontinued Operations
The following table presents discontinued operations for the years ended December 31, 2010 and 2009 (in millions):
The change in discontinued operations was primarily attributable to the related transactions being completed in the prior year, with no impact to 2010.
Income Attributable to Noncontrolling Interest
The following table presents income attributable to noncontrolling interest for the years ended December 31, 2010 and 2009 (in millions):
Income attributable to noncontrolling interest of $83.5 million for the Year Ended December 31, 2010 represents Rio Tinto's interest in CPE Resources net income for the period from January 1, 2010 through December 15, 2010. The portion of net income that is attributable to the noncontrolling interest is not equal to 48.3% of consolidated equity or of consolidated net income due to the effects of income taxes and related agreements that pertain solely to Cloud Peak Energy Inc as well as the timing of the Secondary Offering. Specifically, the $19.7 million expense related to the change in the Tax agreement liability and related adjustments of $5.4 million to the net value of deferred tax assets are not attributable to the noncontrolling interest. There was no noncontrolling interest prior to our IPO on November 19, 2009 or after the Secondary Offering on December 15, 2010.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
During the first half of 2008, due to a favorable supply and demand balance for PRB coal, increasing prices for our coal enabled us to enter into long-term contracts at higher prices. Since mid-2008, however, the economic downturn, particularly with respect to the U.S. economy, coupled with the global financial and credit market disruptions, had an adverse impact on the coal industry. As a result of our long-term contracting strategy, in which we enter into forward contracts for a significant portion of our coal, we experience a lag in revenue trends compared to spot price fluctuations.
Consequently, despite a decrease in tons sold from 2008 to 2009, we experienced an increase in total revenues from sales of coal.
The weak market conditions during 2009 resulted in decreased demand for our coal and lower spot prices, and the fixed price contracts we entered into for future sales were at lower prices than the contractual prices we were able to achieve in 2008 for future sales. These lower prices will negatively impact our future revenues for the contractual periods, which historically have been one to five years; however, we are currently experiencing a period where we, and our customers, are seeking to enter into contracts with shorter terms, which may mitigate the impact. To further mitigate the potentially negative impact on our operating results, we have focused our cost management efforts, which resulted in reducing utilization of contractors, lowering employee overtime, and optimizing repairs and maintenance expense.
Revenues
The following table presents revenues for the years ended December 31, 2009 and 2008 (in millions):
The increase in revenues from our owned an operated mines reflects a 13.5% increase in the average price per ton of coal sold, from $10.44 in 2008 to $11.85 in 2009, and a 3.0% decrease in shipments, from 93.7 tons in 2008 to 90.9 million tons in 2009. The increase in average price per ton sold reflects the strong demand for PRB coal due to prevailing economic and industry conditions at the time we entered into the related coal supply contracts. The decrease in volume reflects the downturn in the overall economic conditions in the U.S. markets near the end of 2008 and continuing into 2009, which resulted in certain customers not taking all of their contracted purchases of coal. Our share of revenues from coal produced at the Decker mine decreased, reflecting a decline in shipments partially offset by higher average price per ton.
The balance of our revenues consist primarily of broker coal sales including revenues from our significant broker sales contract that expired in 2010 of $140.4 million and $135.1 million for the years 2009 and 2008, respectively, and billings for transportation and delivery services. Other broker coal sales increased by $28.1 million in 2009 compared to 2008, reflecting increases in shipments and average selling prices. Revenues from transportation and delivery services increased by $39.6 million, as a result of a higher volume of coal sold on a delivered basis, including export sales with delivered pricing terms that include rail and port charges, where we arranged and paid for the freight costs and charged our customers on a cost-plus basis for providing this service. Other revenues, which in 2008 included $6.3 million from a Decker contract settlement, decreased $5.1 million in 2009.
Cost of Product Sold
The following table presents cost of product sold for the years ended December 31, 2009 and 2008 (in millions):
The largest component of cost of product sold is the cost of coal produced at the three mines that we own and operate. The moderate decrease reflects the 3.0% decrease in tons shipped from our mines, partially offset by 2.1% increase in the cost per ton of coal produced, from $7.79 in 2008 to $7.95 in 2009. The increase in the cost per ton of coal produced is primarily the result of an 11.0% per ton increase in royalties and production taxes which reflects the higher average sales prices realized on our 2009 coal shipments. Excluding royalties and production taxes, the cost per ton of coal produced declined from $4.70 to $4.52, primarily reflecting decreases in unit costs for fuel, lubricants and explosives, as a result of lower prevailing commodity prices in 2009, partially offset by moderate increases in unit costs for labor, repairs and supplies. The cost of coal produced by the Decker mine decreased $5.3 million in 2009, reflecting lower production volumes partially offset by higher unit production costs.
Cost of product sold also increased in 2009 due to the greater volume of sales on a delivered basis, where we arranged transportation, resulting in a $27.8 million increase in freight and handling costs. In addition, the cost of purchased coal increased $24.2 million, including increases of $2.0 million for our significant broker sales contract that expired in 2010 and $22.2 million for other broker sales, consistent with the related increase in broker sales revenues in 2009.
Operating Income
The following table presents operating income for the years ended December 31, 2009 and 2008 (in millions):
Operating income was affected by the following other factors not discussed above:
•An increase of $7.9 million in depletion of reclamation costs as a result of an increase in estimated reclamation costs for a mined-out portion of the Decker mine while the 2008 amount reflected a favorable adjustment upon the addition of new coal reserves at the Cordero Rojo mine. In addition, depreciation increased $2.3 million as a result of a higher capital base, following increased investment and capital expenditures in recent years. These increases were partially offset by a decrease in depletion of $1.6 million resulting from fewer tons produced in 2009 as compared to 2008, as depreciation and depletion are calculated predominantly on a units-of-production basis.
•A decrease in amortization attributable to the buy out of a long-term contract at the Decker mine in the first quarter of 2008, which resulted in accelerated amortization of the intangible asset associated with the contract in 2008. In addition, this intangible asset was fully impaired
later in 2008 as a result of a change in the Decker mine plan during the fourth quarter, resulting in no amortization of the intangible asset being recognized during 2009. Further contributing to the decrease was a reduction in amortization related to a coal supply contract that expired in 2010.
Total Other Expense
The following table presents total other expense for the years ended December 31, 2009 and 2008 (in millions):
Total other expense declined primarily due to a decrease in interest expense, which declined due to the termination on September 24, 2008 of the RTA Facility, under which we incurred interest of $16.8 million in 2008. Interest expense will increase going forward as a result of the debt financing transactions entered into in connection with the IPO. See "-Liquidity and Capital Resources-Senior Unsecured Notes and Senior Secured Revolving Credit Facility" below.
Income Tax Provision
The following table presents our income tax provision for the years ended December 31, 2009 and 2008 (in millions):
Income tax expense increased primarily due to higher income before taxes. The increase in effective tax rate in 2009 was primarily due to a reduction in tax benefits received for percentage depletion deductions. The adjustment to the effective tax rate for the post-IPO period in 2009 to account for pretax income attributable to the noncontrolling interest reduced our effective tax rate by approximately 1.5%. See Note 13 of Notes to Consolidated Financial Statements in Item 8.
Discontinued Operations
The following table presents income (loss) from discontinued operations for the years ended December 31, 2009 and 2008 (in millions):
*Change from prior period is not a relevant percentage
The favorable change in income from discontinued operations was primarily attributable to income from the Jacobs Ranch mine, which was sold on October 1, 2009, resulting in a pre-tax gain of $264.8 million. Jacobs Ranch mine operating income prior to disposal improved by $69.4 million due to higher coal prices and the cessation of depreciation, depletion and amortization as a result of the assets
being classified as held for sale as of March 1, 2009. These favorable changes were partially offset by a $119.0 million increase in related income taxes. The overall increase in income from discontinued operations also reflects the absence in 2009 of net losses incurred at the Colowyo mine and the uranium mining venture after RTEA transferred its interests in the property to Rio Tinto America in October 2008.
Liquidity and Capital Resources
Total cash comprises cash and cash equivalents and restricted cash. As of December 31, 2010 and 2009, total cash was $522.2 million and $348.5 million, respectively. These amounts included cash and cash equivalents of $340.1 million and $268.3 million, respectively, and restricted cash of $182.1 million and $80.2 million, respectively. Restricted cash collateralizes certain of our surety bond obligations at collateral levels that were established by our surety bond providers in 2009 following our IPO. As of December 31, 2009, our surety bonds were generally collateralized using Rio Tinto's balance sheet and letters of credit. During 2010, we posted $218.4 million in restricted cash collateral as we replaced Rio Tinto's surety bonds. We used restricted cash to avoid the fees associated with letters of credit, which can also be used as collateral. In the fourth quarter of 2010 we were successful in releasing $36.3 million of collateral from our surety program and this balance is reflected in our cash and cash equivalents. Prior to our IPO, substantially all of our cash balances, except cash held by Decker, were transferred to Rio Tinto in accordance with the Rio Tinto cash management arrangement.
In addition to our cash and cash equivalents, our primary sources of liquidity are cash from our operations and borrowing capacity under our $400 million revolving credit facility. Cash from operations depends on a number of factors beyond our control, such as the market price for our coal, the quantity of coal required by our customers, coal-fired electricity demand, regulatory changes impacting our business, reclamation costs, the market price we pay for diesel fuel, variables affecting other costs of our business and other risks and uncertainties, including those discussed in Item 1A "Risk Factors."
The borrowing capacity under our revolving credit facility is reduced by the amount of letters of credit issued. As of December 31, 2010, our borrowing capacity under the revolving credit facility was $389.5 million. Our ability to borrow under our revolving credit facility is subject to the terms and conditions of the facility, including our compliance with financial and non-financial covenants.
We believe these sources will be sufficient to fund our primary uses of cash for the next twelve months, which include our costs of coal production, federal coal lease installment payments for existing and new LBAs, capital expenditures, interest on our debt and payments to RTEA under our Tax Receivable Agreement.
We intend to seek increases in our reserve position by acquiring federal coal and surface rights adjoining our current operations in Wyoming and Montana. Through the LBA process, we have nominated large coal tracts adjacent to our existing operations. If we are awarded new coal leases, which may occur as early as 2011, our cash flows could be significantly impacted as we would be required to make the initial lease payment and annual payments thereafter. We will continue to explore additional opportunities to increase our reserve base.
In addition, our anticipated capital expenditures, which we expect will be between $100 million and $140 million (excluding federal coal lease payments) in 2011, include our estimates of expenditures necessary to keep our current fleets updated to maintain our mining productivity and competitive position and the addition of new equipment as necessary.
We are required to make semi-annual interest payments on our senior notes, which commenced on June 15, 2010. We also expect to make on-going payments to RTEA under the Tax Receivable Agreement, which will impact our liquidity.
If we do not have sufficient resources to satisfy our obligations, we may need to borrow money or take other actions. We may not be able to obtain additional funding on acceptable terms or at all. In addition, our existing debt instruments contain restrictive covenants, which may prohibit us from adopting certain alternatives to obtain additional funding.
Overview of Cash Transactions in 2010
We started 2010 with $268.3 million of unrestricted cash and cash equivalents. After making interest and private and federal coal lease payments of $53.0 million and $65.4 million, respectively, capital expenditures of $65.0 million and generating $322.7 million of Adjusted EBITDA, we ended the year with $340.1 million of unrestricted cash and cash equivalents. We started 2010 with $80.2 million of restricted cash. During the first half of 2010, we contributed an additional $138.2 million of cash and cash equivalents to restricted cash to collateralize our surety and performance bond obligations. We released $36.3 million of collateral in the fourth quarter of 2010 following a negotiated reduction of the collateral required. We ended the year with $182.1 million of restricted cash.
Continuing Operations
The following table summarizes operating cash flows for the years ended December 31, 2010 and 2009 (in millions):
The increase from adjustments before changes in working capital was largely due to a change in deferred taxes. The decrease in working capital was largely driven by a reduction in related party receivables as a result of changes in our relationship with Rio Tinto through the IPO structuring transactions.
The following table summarizes investing cash flows for the years ended December 31, 2010 and 2009 (in millions):
The decrease in cash used in investing activities from continuing operations was primarily the result of a $217.5 million decrease in cash advances to affiliates as a result of the cessation of the cash management program we were under with Rio Tinto prior to the IPO structuring transactions and a $28.1 million decrease in the cash paid for property, plant and equipment, including capitalized interest. Year-to-date property, plant, and equipment purchases include the acquisition of the lease by modification at the Spring Creek mine and the purchase of approximately 19 million tons of privately held coal. These decreases were partially offset by a $101.9 million increase in restricted cash to collateralize surety bonds obligations.
The following table summarizes financing cash flows for the years ended December 31, 2010 and 2009 (in millions):
*Change from prior period is not a relevant percentage
During 2010, we made distributions to Rio Tinto totaling $10.2 million and principal payments for coal lease obligations of $50.8 million. Distributions to Rio Tinto were required by the CPE Resources limited liability company agreement and correspond to distributions made to Cloud Peak Energy Inc. Cash used in financing activities from continuing operations during 2009 was comprised of approximately $1.52 billion in distributions to Rio Tinto offset by approximately $1.0 billion in net proceeds from the senior notes offering and the IPO, all of which occurred in 2009.
The following table summarizes operating cash flows for the years ended December 31, 2009 and 2008 (in millions):
This increase reflects a $201.5 million change in the effects of transactions with related parties. In the year ended December 31, 2008, we made payments to affiliates that resulted in a $129.3 million net reduction in amounts due to related parties, while in 2009 no similar payments were made and the amounts due to related parties increased by $103.4 million, reflecting expenses incurred by related parties on our behalf. The increase in operating cash flow also reflects a $94.1 million increase in income from continuing operations and a $32.3 million increase in deferred income taxes, partially offset by a $26.5 million decrease in non-cash expenses. The decrease in non-cash expenses is primarily related to amortization expense and interest expense converted to principal.
The following table summarizes investing cash flows for the years ended December 31, 2009 and 2008 (in millions):
The increase in cash used in investing activities from continuing operations was primarily the result of a $182.5 million increase in amounts invested in the Rio Tinto America cash management program, an $80.2 million increase in restricted cash and a $21.4 million decrease in net receipts of refundable deposits related to coal reserve acquisition bids partially offset by a $18.4 million decrease in purchases of property, plant and equipment.
The following table summarizes financing cash flows for the years ended December 31, 2009 and 2008 (in millions):
*Change from prior period is not a relevant percentage
The increase in cash used in financing activities from continuing operations is primarily attributable to approximately $1.52 billion in distributions to Rio Tinto, $764.1 million of which represented the proceeds from the sale of the Jacobs Ranch mine, $309.7 million of which was funded by the proceeds of our senior notes offering, and $433.8 million represented the net proceeds from our IPO. Also contributing to the use of cash was a $29.2 million increase in payments on long-term debt, including federal coal leases, and net borrowings and repayments on the RTA Facility during the year ended December 31, 2008 that did not occur in 2009. Partially offsetting these increases was $568.7 in net proceeds from our senior notes offering.
Discontinued Operations
Net cash provided by operating activities from discontinued operations was $36.0 million and $50.3 million for the years ended December 31, 2009 and 2008, respectively. The $14.3 million decrease in net cash provided by operating activities from discontinued operations for the year ended December 31, 2009 compared to 2008 was due primarily to an increase in royalty and production tax payments.
Net cash provided by investing activities from discontinued operations was $759.0 million for the year ended December 31, 2009, compared to net cash used in investing activities from discontinued operations of $41.2 million for the year ended December 31, 2008. Our 2009 cash flows reflect proceeds of $764.1 million from the sale of the Jacobs Ranch mine, which was completed on October 1, 2009.
There was no cash used or provided from financing activities for discontinued operations during 2009 due to the absence of Colowyo financing activities as a result of the October 2008 disposal of Colowyo.
Senior Unsecured Notes
We refer to the $300.0 million senior notes due December 15, 2017 (the "2017 Notes") and the $300.0 million senior notes due December 15, 2019 (the "2019 Notes") collectively as the senior notes. The 2017 Notes and 2019 Notes bear interest at fixed annual rates of 8.25% and 8.50%, respectively. There is no mandatory redemption or sinking fund payments for the senior notes and interest payments are due semi-annually on June 15 and December 15, beginning on June 15, 2010. Subject to certain limitations, we may redeem the 2017 Notes by paying specified redemption prices in excess of their principal amount prior to December 15, 2015, or by paying their principal amount thereafter. Similarly, we may redeem the 2019 Notes by paying specified redemption prices in excess of their principal amount prior to December 15, 2017, or by paying their principal amount thereafter.
In connection with our IPO structuring transactions, we distributed $309.7 million of the net proceeds to RTEA during the fourth quarter of 2009. The remaining net proceeds from the senior notes offering were designated for general corporate purposes.
The senior notes are jointly and severally guaranteed by all of our existing and future restricted subsidiaries that guarantee our debt under our credit facility. See "-Senior Secured Revolving Credit Facility" below. Substantially all of our consolidated subsidiaries, excluding Decker Coal Company, are considered to be restricted subsidiaries and guarantee the senior notes.
The indenture governing the senior notes, among other things, limits our ability and the ability of our restricted subsidiaries to incur additional indebtedness and issue preferred equity; pay dividends or distributions; repurchase equity or repay subordinated indebtedness; make investments or certain other restricted payments; create liens; sell assets; enter into agreements that restrict dividends, distributions or other payments from restricted subsidiaries; enter into transactions with affiliates; and consolidate, merge or transfer all or substantially all of their assets and the assets of their restricted subsidiaries on a combined basis.
Upon the occurrence of certain transactions constituting a "change in control" as defined in the indenture, holders of our notes could require us to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase.
Senior Secured Revolving Credit Facility
Concurrent with the offering of the senior notes, we entered into a $400.0 million senior secured revolving credit facility, or credit facility, with a syndicate of lenders, the full amount of which is available for use in connection with loans or the issuance of letters of credit. Our obligations under the credit facility are supported by a guarantee by our domestic restricted subsidiaries. The credit facility matures on December 16, 2013. As of December 31, 2010, there were no amounts drawn under the credit facility and $10.5 million was committed in connection with the issuance of letters of credit. The letters of credit are used as collateral to secure our obligations to reclaim lands used for mining. See "-Off-Balance Sheet Arrangements" below.
Loans under the credit facility bear interest at the greater of the LIBOR or 2.50%, plus an applicable margin based on our credit rating of between 3.25% and 4.25% depending on our credit rating (4.00% at December 31, 2010). We are required to pay the lenders a commitment fee of 0.75% per year on the unused amount of the credit facility. Letters of credit issued under the credit facility, unless drawn upon, will bear interest at the applicable margin for LIBOR loans from the date at which they are issued. In addition, in connection with the issuance of a letter of credit we will be required to
pay the issuing bank a fronting fee of 0.25% plus additional customary administrative fees and expenses.
Our obligations under the credit facility are secured by substantially all of our assets and substantially all of the assets of certain of our subsidiaries, subject to certain permitted liens and to customary exceptions for similar coal financings. We are subject to financial maintenance covenants based on EBITDA (which is defined in the credit agreement and is not the same as EBITDA or Adjusted EBITDA presented elsewhere in this report) requiring us to maintain defined minimum levels of interest coverage and providing for a limitation on our total and first lien senior secured debt leverage ratios. Specifically, the credit agreement requires us to maintain a ratio of EBITDA to consolidated net cash interest expense equal to or greater than 2.75 to 1, a ratio of funded debt to EBITDA equal to or less than 3.5 to 1, and a ratio of first lien senior secured debt to EBITDA equal to or less than 1.5 to 1 as long as the credit facility is in effect.
Our credit facility also requires us to comply with non-financial covenants that restrict certain corporate activities and certain of our subsidiaries and contains customary events of default with customary grace periods and thresholds. These covenants include restrictions on our ability to incur additional debt and pay dividends, among other restrictive covenants. Our ability to access the available funds under our credit facility may be impaired in the event that we do not comply with the covenant requirements or if we default on our obligations under the agreement. In addition, under the terms of our credit facility, a change in control of Cloud Peak Energy Inc. or CPE Resources will result in an automatic event of default and, unless waived by the required lenders, will result in all obligations under the agreement becoming immediately due and payable. At December 31, 2010, we were in compliance with the covenants contained in our credit facility.
Federal Coal Leases
Our federal coal lease obligations consist of amounts payable to the BLM under leases, each of which require five equal annual payments. The remaining aggregate annual payments under our existing federal coal leases total $133.2 million, with $63.8 million due in 2011, $59.8 million due in 2012 and $9.6 million due in 2013. We recognize imputed interest on federal coal leases based on an estimate of the credit-adjusted, risk-free rate reflecting our estimated credit rating at the inception of the lease. The outstanding principal balance of our federal coal lease obligations was $118.3 million as of December 31, 2010.
Off-Balance Sheet Arrangements
In the normal course of business, we are party to a number of arrangements that secure our performance under certain legal obligations. These arrangements include letters of credit and surety bonds. We use these arrangements primarily to comply with federal and state laws that require us to secure the performance of certain long-term obligations, such as mine closure or reclamation costs, coal lease obligations, state workers' compensation and federal black lung liabilities. These arrangements are typically renewable annually.
Liabilities related to these arrangements are not reflected in our consolidated balance sheets. While we were a subsidiary of Rio Tinto, Rio Tinto maintained our surety bonds and facilitated the issuance of letters of credit on our behalf. Pursuant to our IPO Structuring Agreements, we agreed to use our commercially reasonable efforts to obtain new surety bonds, letters of credit or other credit arrangements and to obtain the full release of Rio Tinto with respect to any existing arrangements.
As of December 31, 2009, with the exception of our obligations with respect to Decker, Rio Tinto remained the guarantor and we maintained $80.2 million in restricted cash as collateral for the benefit of Rio Tinto. We completed the replacement of surety bonds and letters of credit provided by Rio
Tinto on our behalf during 2010. These surety bonds are collateralized by a restricted cash balance of $182.1 million.
As of December 31, 2010, we used surety bonds and letters of credit to secure outstanding obligations as follows (in millions):
(1)Reclamation obligations include amounts to secure performance related to our outstanding obligations to reclaim areas disturbed by our mining activities and are a requirement under our state mining permits. Includes $74.2 million representing our 50% share of surety bonds securing Decker's reclamation obligations and $10.5 million in letters of credit issued under our revolving credit facility to secure our 50% share of additional Decker reclamation obligations.
(2)Lease obligations include amounts generally required as a condition to state or federal coal leases; the amounts vary and are mandated by the governing agency.
(3)Other obligations include amounts required for exploration permits, water well construction and monitoring and other miscellaneous items as mandated by the applicable governing agencies.
(4)We are required to collateralize our surety bonds with cash or letters of credit. We can substitute collateral, at our discretion.
Our outstanding surety bonds in respect of our reclamation and lease obligations were $525.0 million at December 31, 2010 (including our obligations with respect to the Decker mine) and are required by law. State statutes regulate and determine the calculation of the amounts of the bonds that we are required to hold. We do not believe that these state-mandated estimates are a true reflection of what our actual reclamation costs will be. Reclamation bond amounts represent an estimate of the near-term reclamation liability that assumes reclamation activities will be performed by a third party during the next one to five years. Because this evaluation is near-term, it is recalculated on a frequent basis, often annually. The basis for calculating bond requirements is substantially different than the requirements that apply to the determination of our asset retirement obligation, or ARO, liability on our consolidated balance sheet, which is determined in accordance with U.S. GAAP. The state calculates our specific bond requirements considering assumed costs that the state would incur if they were required to complete the reclamation on our behalf. Additionally, where a multi-year bond, such as a three to five-year bond, is put into place, the state regulatory authority requires that the reclamation liability must be calculated for the highest cost scenario over that period.
The carrying amount of our reclamation obligations, as determined in accordance with U.S. GAAP, which are reported in our consolidated financial statements, as ARO liabilities, was $182.2 million at December 31, 2010, $6.6 million of which is payable in 2011. We estimate our ARO liabilities based on disturbed acreage to date and third party cost estimates. The estimated ARO liabilities are also based on engineering studies and our engineering expertise related to the reclamation requirements. We also assume that reclamation will be completed after the end of the mine life based on our current reclamation area profiles, which may be a different land disturbance assumption than the state requires, as we perform reclamation concurrently with our mining activities. We have estimated that we will perform concurrent reclamation of approximately $5.9 million during 2011. Concurrent reclamation is performed on an annual basis as a part of our normal mining operations. Finally, the carrying amount of our ARO liabilities reflects discounting of estimated reclamation costs using a credit-adjusted risk-free interest rate. For a discussion of the risks relating to our reclamation obligations, see Item 1A "Risk Factors-Risks Related to Our Business and Industry-If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated or be incurred sooner than anticipated."
Because we are required by state and federal law to have these bonds or letters of credit in place before mining can commence, or continue, our failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal. That failure could result from a variety of factors including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of any credit facility then in place. See Note 17 of Notes to Consolidated Financial Statements in Item 8.
Contractual Obligations
As of December 31, 2010, we had the following contractual obligations (in millions):
(1)CPE Resources issued $600.0 million aggregate principal amount of senior notes in two tranches due 2017 and 2019. CPE Resources also has entered into a $400.0 million four-year revolving credit facility, none of which had been drawn as of December 31, 2010. See Note 9 of Notes to Consolidated Financial Statements in Item 8.
(2)Coal lease obligations include our discounted payment obligations under federal coal leases, private coal leases and land purchase notes. See Note 10 of Notes to Consolidated Financial Statements in Item 8.
(3)As of December 31, 2010, we had outstanding commitments for interest related to our senior notes, private coal lease and land purchase notes, and imputed interest for our federal coal lease obligations. See Notes 9 and 10 of Notes to Consolidated Financial Statements in Item 8.
(4)As of December 31, 2010, we had outstanding commitments for coal purchases and capital expenditures which are not included on consolidated balance sheet. See Note 17 of Notes to Consolidated Financial Statements in Item 8.
This table does not include our estimated AROs. As discussed in "Critical Accounting Policies and Estimates-Asset Retirement Obligations" below, the current and noncurrent carrying amount of our AROs involves a number of estimates, including the amount and timing of the payments to satisfy these obligations. The timing of payments is based on numerous factors, including projected mine closing dates. Based on our assumptions, the carrying amount of our AROs (excluding concurrent reclamation) as determined in accordance with U.S. GAAP is $188.8 million as of December 31, 2010. See Note 11 of Notes to Consolidated Financial Statements in Item 8.
This table does not include our contractual obligations related to an agreement we entered into in April 2008 to purchase land adjacent to our Antelope mine, whereby the seller may require us to pay a purchase price of up to $23.7 million, which will close between April 2013 and April 2018.
This table does not include payments that we expect to make under the Tax Receivable Agreement. We have recognized a $190.1 million liability for our estimated payments to RTEA under the Tax Receivable Agreement, of which $18.2 million and $171.9 million is classified as current and noncurrent, respectively, as of December 31, 2010. The estimated liability is based on forecasts of future taxable income over the anticipated life of our mining operations and reclamation activities, assuming no additional coal reserves are acquired. The assumptions used in our forecasts are subject to substantial uncertainty about our future business operations and the actual payments that we are required to make under the Tax Receivable Agreement could differ materially from our estimates. Based on our estimates as of December 31, 2010, we expect to make payments of $18.2 million in 2011 and payments averaging approximately $24.5 million during 2012 to 2015. See Item 1A "Risk Factors-Risks Related to Our Corporate Structure-We are required to pay RTEA for most of the tax benefits we may claim as a result of the tax basis step-up we received in connection with our IPO, related IPO structuring transactions and the Secondary Offering. In certain cases, payments to RTEA may be accelerated or exceed our actual cash tax savings. These provisions may deter a change in control of our company."
Critical Accounting Policies and Estimates
We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the U.S. These accounting principles require us to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, and revenues and expenses, as well as the disclosure of contingent assets and liabilities. We base our judgments, estimates and assumptions on historical information and other known factors that we deem relevant. Estimates are inherently subjective, as significant management judgment is required regarding the assumptions utilized to calculate accounting estimates in our consolidated financial statements, including the notes thereto. Our significant accounting policies are described in Note 3 of Notes to Consolidated Financial Statements in Item 8. This section describes those accounting policies and estimates that we believe are critical to understanding our consolidated financial statements.
Revenue Recognition
Revenues from coal sales are recognized when a customer takes delivery of our coal, which usually occurs at the time of shipment from our mine. Some coal supply agreements provide for price adjustments based on variations in quality characteristics of the coal shipped. In certain cases, a customer's analysis of the coal quality is binding and the results of the analysis are received on a delayed basis. In these cases, we estimate the amount of the quality adjustment and adjust the estimate
to actual when the information is provided by the customer. Historically such adjustments have not been material.
Asset Retirement Obligations
Our AROs arise from the SMCRA and similar state statutes. These regulations require that we, upon closure of a mine, restore the mine property in accordance with an approved reclamation plan issued in conjunction with our mining permit.
Our AROs are recorded initially at fair value, or the amount at which we estimate we could transfer our future reclamation obligations to informed and willing third parties. We use estimates of future third party costs to arrive at the AROs because the fair value of such costs generally reflects a profit component. It has been our practice, and we anticipate it will continue to be our practice, to perform a substantial portion of the reclamation work using internal resources. Hence, the estimated costs used in determining the carrying amount of our AROs may exceed the amounts that are eventually paid for reclamation costs if the reclamation work is performed using internal resources.
To determine our AROs, we calculate on a mine-by-mine basis the present value of estimated future reclamation cash flows based upon each mine's permit requirements, estimates of the current disturbed acreage subject to reclamation, which is based upon approved mining plans, estimates of future reclamation costs and assumptions regarding the mine's productivity, which are based on engineering estimates that include estimates of volumes of earth and topsoil to be moved, the use of particular pieces of large mining equipment to move the earth and the operating costs for those pieces of equipment. These cash flow estimates are discounted at an adjusted, risk-free interest rate based on U.S. Treasury bonds with a maturity similar to the expected life of the mine.
The amount initially recorded as an ARO for a mine may change as a result of mining permit changes granted by mining regulators, changes in the timing of mining activities and the mine's productivity from original estimates and changes in the estimated costs or the timing of reclamation activities. We periodically update estimates of cash expenditures to meet each mine's reclamation requirements and we adjust the ARO in accordance with U.S. GAAP, which generally requires a measurement of the present value of any increase in estimated reclamation costs using an adjusted, risk-free interest rate based on U.S. Treasury bonds with a maturity similar to the expected remaining life of the mine. Adjustments to the ARO for decreases in the estimated amount of reclamation costs are measured using an adjusted, risk-free interest rate as of the date of the initial recognition of the ARO. Annually, we analyze AROs on a mine-by-mine basis and, if necessary, adjust the balance to take into account any changes in estimates.
Federal Coal Leases
Upon the award date of federal coal leases, pursuant to which payments are required to be paid in equal annual installments, we recognize an asset for the related mineral rights in property, plant and equipment and a corresponding liability for our future payment obligations in long-term debt. The amount recognized as an asset is the sum of the initial installment due at the effective date of the lease and the amount recognized in long-term debt, which reflects the present value of the remaining installments. We determine the present value of the remaining installments using an estimate of the credit-adjusted, risk-free rate that reflects our credit rating. Interest is recognized over the term of the lease based on the imputed interest rate that was used to determine the initial long-term debt amount on the effective date. Such interest may be capitalized while activities are in progress to prepare the acquired coal reserves for mining. The mineral rights asset recorded at the effective date is eventually recognized in depreciation and depletion expense using the units-of-production method over the period the related coal reserves are mined.
Income Taxes and Tax Agreement Liability
Our consolidated deferred tax assets as of December 31, 2010 were $162.5 million, net of a $94.6 million valuation allowance. If future taxable income differs from our estimates or if expected tax planning strategies are not available as anticipated, adjustments to the valuation allowance may be needed. Periodically, we evaluate the realizability of our deferred tax assets and adjust the related valuation allowance to reflect our updated estimate of the tax benefits that are more likely than not to be realized. Our evaluation is based on our consideration of CPE Resources historical operations, the effects of the structuring and financing transactions completed in connection with our IPO and Secondary Offering, updated forecasts of taxable income over the remaining lives of our mines, the availability of tax planning strategies and other factors.
We have recognized a tax agreement liability reflecting our estimate of the undiscounted amounts that we expect to pay to RTEA under this agreement. Periodically, we adjust the liability based on an updated estimate of the amounts that we expect to pay, using assumptions consistent with those used in our concurrent estimate of the deferred tax asset valuation allowance. These periodic adjustments to the tax agreement liability are reflected in our consolidated pre-tax income, and may also result in corresponding adjustments to our income tax expense and deferred income tax accounts. Acquisitions of additional coal leases are likely to increase our tax agreement liability and related deferred tax asset in the future. Although our periodic adjustments to the deferred tax asset valuation allowance and tax agreement liability are based on consistent assumptions, the calculations required to determine these estimates differ in certain respects and the related adjustments will not have offsetting or proportionate effects on our earnings. In addition, our estimates reflect assumptions about future events that are inherently uncertain. Accordingly, our periodic adjustments to the deferred tax asset valuation allowance and the tax agreement liability may have material and unpredictable effects on our consolidated financial statements.
Seasonality
Our business has historically experienced only limited variability in its results due to the effect of seasons. Demand for coal-fired power can increase due to unusually hot or cold weather, as power consumers use more air conditioning or heating. Conversely, mild weather can result in softer demand for our coal. Adverse weather conditions, such as blizzards or floods, can impact our ability to mine and ship our coal, and our customers' ability to take delivery of coal.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
We define market risk as the risk of economic loss as a consequence of the adverse movement of market rates and prices. We believe our principal market risks are commodity price risk and interest rate risk.
Commodity Price Risks
Market risk includes the potential for changes in the market value of our coal portfolio. Due to the lack of quoted market prices and the long-term nature of our forward sales position, we have not quantified the market risk related to our coal supply agreements. Historically, we have principally managed the commodity price risk for our coal contract portfolio through the use of long-term coal supply agreements of varying terms and durations, rather than through the use of derivative instruments.
We also face price risk involving other commodities used in our production process such as diesel fuel. Based on our projections of our usage of diesel fuel for the next 12 months, and assuming that the average cost of diesel fuel increases by 10%, we would incur additional fuel costs of approximately
$9 million over the next twelve months. Historically, we have not hedged commodities such as diesel fuel. We may enter into hedging arrangements in the future.
Interest Rate Risk
Our credit facility is subject to an adjustable interest rate. See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Senior Secured Revolving Credit Facility." We had no outstanding borrowings under our credit facility as of December 31, 2010. If we borrow funds under the revolving credit facility, we may be subject to increased sensitivity to interest rate movements. Any future debt arrangements that we enter into may also have adjustable interest rates that may increase our sensitivity to interest rate movements.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Cloud Peak Energy Inc.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, equity and cash flows present fairly, in all material respects, the financial position of Cloud Peak Energy Inc. and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our audits (which was an integrated audit in 2010). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
Denver, Colorado
February 24, 2011
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(dollars in thousands, except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Business
Cloud Peak Energy Inc. ("CPE Inc.") was incorporated in Delaware on July 31, 2008 and had no business operations prior to November 19, 2009, when it acquired its coal business in connection with the initial public offering of its common stock ("IPO"). Prior to its IPO, CPE Inc. was a wholly-owned subsidiary of Rio Tinto America Inc. ("Rio Tinto America") and was an indirect subsidiary of Rio Tinto plc ("Rio Tinto"), one of the largest mining companies in the world. CPE Inc. used the net proceeds from its IPO to repay a promissory note that was issued on November 19, 2009 in exchange for the managing member interest in Cloud Peak Energy Resources LLC ("CPE Resources") from Rio Tinto Energy America Inc. ("RTEA"), a wholly-owned subsidiary of Rio Tinto America that historically had operated Rio Tinto's western United States ("U.S.") coal business. CPE Resources was formed as Rio Tinto Sage LLC on August 19, 2008 and was renamed Cloud Peak Energy Resources LLC in November 2009. RTEA was formed in March 1993 as Kennecott Coal Company and was renamed Rio Tinto Energy America Inc. in May 2006. Prior to the IPO, RTEA had contributed to CPE Resources substantially all of the assets used in Rio Tinto's western U.S. coal business.
On December 15, 2010, Cloud Peak Energy Inc. priced a secondary offering of 29,400,000 shares of its common stock on behalf of Rio Tinto. In connection with the secondary offering, we exchanged 29,400,000 shares of common stock for the common membership units of CPE Resources held by Rio Tinto and completed the secondary offering on behalf of Rio Tinto (the "Secondary Offering"), resulting in a divestiture of 100% of Rio Tinto's holdings in CPE Resources. As a result of this transaction, CPE Resources is now a wholly-owned subsidiary of Cloud Peak Energy Inc, and Rio Tinto no longer holds an interest in CPE Resources.
Through CPE Resources and its subsidiaries, CPE Inc. engages in coal mining operations in the Powder River Basin ("PRB"), the lowest cost coal producing region in the U.S., and operates two of the four largest coal mines in the region and in the U.S. CPE Resources operates three surface coal mines, of which two are in Wyoming and one is in Montana, and owns a 50% interest in another surface coal mine in Montana. CPE Resources produces sub-bituminous steam coal with low sulfur content and sells the coal primarily to electric utility companies, which use the coal as fuel for electricity generation.
"Cloud Peak Energy," "we," "us," "our" or the "Company" refer collectively to CPE Inc., CPE Resources and their consolidated subsidiaries. Those terms also include RTEA with respect to periods prior to our IPO, when RTEA was the parent company of CPE Resources and its subsidiaries.
2. Basis of Presentation
Principles of Consolidation
Our consolidated financial statements present the financial position, results of operations and cash flows of our business, which was controlled by Rio Tinto, through RTEA, prior to our IPO and by CPE Inc. thereafter. For dates and periods prior to our IPO, our consolidated financial statements present RTEA as the parent company (the "former parent") and reflect allocations of certain costs incurred by other Rio Tinto affiliates. For dates and periods following our IPO but preceding our Secondary Offering, our consolidated financial statements present CPE Inc. as the parent company and present Rio Tinto's remaining interest in CPE Resources as a noncontrolling interest. Dates and periods following our Secondary Offering present CPE Inc. as the sole owner in CPE Resources.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Basis of Presentation (Continued)
We consolidate the accounts of entities in which we have a controlling financial interest under the voting control model and consolidate the accounts of variable interest entities for which we are the primary beneficiary. We account for our 50% interest in Decker Coal Company ("Decker") using the proportionate consolidation method, whereby our share of Decker's assets, liabilities, revenues and expenses are included in our consolidated financial statements. Investments in other entities that we do not control but have the ability to exercise significant influence over the investee's operating and financial policies, are accounted for under the equity method. The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the U.S. ("U.S. GAAP"). All intercompany balances and transactions have been eliminated in the consolidated financial statements.
Initial Public Offering, Related IPO Structuring Transactions, and Secondary Offering
Initial Public Offering, Related IPO Structuring Transactions
In anticipation of an IPO or divestment transaction, substantially all assets used in Rio Tinto's western U.S. coal business were transferred to CPE Resources during 2008 and 2009, including Cloud Peak Energy Services Company (formerly known as Rio Tinto Energy America Services Company), or CPESC, which employs personnel who operate the business of CPE Resources. On November 17, 2009, CPE Resources declared a cash distribution to RTEA in anticipation of its senior notes offering (see Note 9). CPE Resources made payments to RTEA totaling $309.7 million pursuant to this declaration and a related working capital adjustment prior to December 31, 2009. These distributions were charged to former parent's equity. On November 19, 2009, CPE Inc. completed the initial public offering of its common stock. Our IPO resulted in the issuance of 30,600,000 shares at an offering price of $15.00 per share and generated net proceeds of $433.8 million, after deducting offering costs of $25.2 million. CPE Inc. used the net proceeds to repay a promissory note that was issued to acquire from RTEA 30,600,000 common membership units in CPE Resources, representing 51.0% of the 60,000,000 common membership units outstanding as of November 19, 2009. RTEA and a Rio Tinto affiliate retained the remaining 49.0% interest in CPE Resources. The CPE Resources limited liability company agreement was amended in connection with our IPO to designate CPE Inc. as the managing member of CPE Resources. As amended, the limited liability company agreement provided for CPE Inc., as managing member, to control the activities of CPE Resources.
In connection with our IPO, CPE Inc., CPE Resources, RTEA and other Rio Tinto affiliates entered into transactions pursuant to several agreements that affected certain existing obligations of the respective parties and required adjustments to certain assets and liabilities of CPE Resources. These transactions were arranged while the parties were under common control by Rio Tinto and, accordingly, were accounted for as equity transactions, resulting in a $3.8 million charge to former parent's equity.
Following the IPO, CPE Inc. recognized deferred tax assets totaling $105.3 million based on the excess of the increased tax basis over the related carrying amount of the interest for financial reporting, which did not change as a result of our IPO structuring transactions. In addition, CPE Inc. and RTEA entered into a Tax Receivable Agreement, pursuant to which CPE Inc. generally is required to pay to RTEA 85% of the income tax savings that it realizes in the future from the increase in tax basis. See "Tax Receivable Agreement" in Note 17. CPE Inc. recognized an initial $54.5 million undiscounted liability for the amounts it expected to pay RTEA under this agreement. The increase in tax basis and
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Basis of Presentation (Continued)
the obligation pursuant to the Tax Receivable Agreement were arranged while CPE Inc. and RTEA were under common control by Rio Tinto. Accordingly, the $50.8 million net effect of these transactions was recognized in equity, including $4.4 million related to unrecognized pension and postretirement benefit costs, which were credited to several components of accumulated other comprehensive income, and the remainder of $46.4 million, which was credited to additional paid-in capital.
CPE Inc. and RTEA were under common control by Rio Tinto at the time CPE Inc. acquired the controlling interest in CPE Resources from RTEA. In accordance with U.S. GAAP, we did not adjust the carrying amounts of the assets and liabilities of CPE Resources as a result of this transfer. The $433.8 million net proceeds from our IPO are reported in the consolidated statement of equity as increases in common stock and additional paid-in capital, and the corresponding payment to RTEA to repay a promissory note that was issued to acquire the controlling interest in CPE Resources is reported as a distribution in former parent's equity. These reported amounts exceed the carrying amount of the transferred interest in the underlying net assets of CPE Resources on the date of transfer by $38.7 million. Accordingly, the consolidated statement of equity reflects offsetting adjustments of $38.7 million to additional paid-in capital and former parent's equity to reduce the reported IPO proceeds and distribution amounts to reflect the carrying amounts of the underlying net assets of CPE Resources.
As a result of CPE Inc.'s acquisition of the controlling interest in CPE Resources from RTEA, effective November 19, 2009, RTEA was no longer our parent company. The consolidated statement of equity includes a $108.5 million increase in former parent's equity to reflect the elimination of RTEA's accounts, consisting primarily of deferred income tax liabilities, accrued royalties and production taxes related to the Jacobs Ranch mine and payables to other Rio Tinto affiliates. In addition, a $2.6 million charge to accumulated other comprehensive loss was recorded to reflect the derecognition of certain tax benefits that RTEA previously had recognized in other comprehensive income.
Secondary Offering
On December 15, 2010, Cloud Peak Energy Inc. priced the Secondary Offering of 29,400,000 shares of its common stock on behalf of Rio Tinto. In connection with the Secondary Offering, we exchanged 29,400,000 shares of common stock for the common membership units of CPE Resources held by Rio Tinto and completed the Secondary Offering, resulting in a divestiture of 100% of Rio Tinto's holdings in CPE Resources. As a result of this transaction, CPE Resources is now a wholly-owned subsidiary of Cloud Peak Energy Inc., and Rio Tinto no longer holds any interest in CPE Resources. The elimination of Rio Tinto as a member results in the elimination of noncontrolling interest as of December 31, 2010. The statement of operations for the year ended December 31, 2010 presents the portion of income attributable to the noncontrolling interest through the date of the Secondary Offering and no income will be attributable to the noncontrolling interest in future periods. The Secondary Offering also resulted in an increase to the undiscounted future liability under the Tax Receivable Agreement of $123.6 million and an increase to our deferred income taxes net of valuation allowance of $93.6 million.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Basis of Presentation (Continued)
Variable Interest Entities
A variable interest entity ("VIE") generally is an entity that is designed to have one or more of the following characteristics: (a) the total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support; (b) as a group, the holders of equity at risk do not have all the characteristics of a controlling financial interest in the entity; or (c) the equity investors have voting rights that are not proportional to their economic interests and substantially all of the entity's activities either involve, or are conducted on behalf of, an investor that has disproportionately few voting rights. A VIE is required to be consolidated in the financial statements of the entity that is determined to hold a controlling financial interest in the VIE. A controlling financial interest is defined as the power to direct the activities of a VIE that most significantly influence the VIE's economic performance and the obligation to absorb the losses of or receive the benefits from the VIE that could potentially be significant to the VIE.
Prior to our IPO, RTEA was the primary beneficiary of Cloud Peak Energy Services Company ("CPESC"), which was an indirect wholly-owned subsidiary of Rio Tinto America. We determined that CPESC was a VIE, primarily because substantially all of CPESC's activities were conducted on behalf of RTEA. We determined that RTEA was the primary beneficiary of CPESC, because RTEA was the Rio Tinto affiliate that was most closely associated with CPESC. As a result, RTEA included CPESC in its consolidated financial statements prior to our IPO. In connection with our IPO structuring transactions, Rio Tinto America contributed CPESC to CPE Resources and we consolidated CPESC based on voting control. Subsequent to the Secondary Offering, CPESC is consolidated as a wholly-owned subsidiary.
Prior to October 7, 2008, we were the primary beneficiary of Colowyo Coal Company, L.P. ("Colowyo"), a VIE with coal mining operations in Colorado. We distributed our equity interests in Colowyo to Rio Tinto America on October 7, 2008, and report the operations of Colowyo prior to that date in discontinued operations (see Note 4).
Pre-IPO Expense Allocations
For periods prior to our IPO, our consolidated financial statements include allocations of certain general and administrative expenses incurred by Rio Tinto America and other Rio Tinto affiliates. Rio Tinto America provided various services and other support to the Company, including tax, treasury, corporate secretary, legal, procurement, information systems and technology, human resources, accounting and insurance/risk management in the ordinary course of business. RTA charged the Company for such services on a unit cost or cost allocation basis, such as per invoice processed, proportion of information technology users, share of time or based on a combination of factors, including revenue, operating expenses and head count. Our consolidated financial statements for periods prior to our IPO also reflect allocations of Rio Tinto's headquarters costs, including costs for technology and innovation, corporate governance, community and external relations, investor relations, human resources and Rio Tinto's Energy and Minerals product group. The allocations were based on a percentage of operating expenses or revenue. We believe that the allocation methodologies reflected in these consolidated financial statements, as described above, were reasonable; however, the allocated expenses are not necessarily indicative of the expenses that would have been incurred if we had been a separate, independent entity.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Basis of Presentation (Continued)
Our consolidated statements of operations include allocations of general and administrative expenses incurred by Rio Tinto America and other Rio Tinto affiliates totaling $20.7 million and $25.4 million for the years ended December 31, 2009 and 2008, respectively. Of these amounts, $15.8 million and $21.0 million for the years ended December 31, 2009 and 2008, respectively, are included in selling, general and administrative expenses. The remaining $4.9 million and $4.4 million for the years ended December 31, 2009 and 2008, respectively, are included in cost of product sold. Also included in selling, general and administrative expenses are costs incurred as a result of actions to divest RTEA, either through a trade sale or an initial public offering, of $18.3 million and $25.8 million for the years ended December 31, 2009 and 2008, respectively.
Reclassifications
Certain amounts in the 2009 and 2008 consolidated financial statements have been reclassified to conform to the 2010 presentation.
3. Critical and Significant Accounting Policies
The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates in these consolidated financial statements include allowances for inventory obsolescence, share-based compensation expense, useful lives of long-lived assets, assumptions about the amount and timing of future cash flows and related discount rates used in determining asset retirement obligations and in testing long-lived assets and goodwill for impairment, the recognition and measurement of income tax benefits and related deferred tax asset valuation allowances, and assumptions about the timing of future cash flows used in determining the tax agreement liability. Actual results could differ materially from those estimates.
Critical Accounting Policies
We consider certain accounting policies to be critical, as their application requires management's judgment about the effects of matters that are inherently uncertain. Following is a discussion of the accounting policies we consider critical to our consolidated financial statements.
Revenue Recognition
We recognize revenue from a sale when persuasive evidence of an arrangement exists, the price is determinable, the product has been delivered, title has transferred to the customer and collection of the sales price is reasonably assured.
Coal sales revenues include sales to customers of coal produced at our facilities and coal purchased from other companies. Coal sales are made to our customers under the terms of coal supply agreements, most of which have a term greater than one year. Under the typical terms of these coal supply agreements, title and risk of loss transfer to the customer at the time the coal is shipped, which is the point at which revenue is recognized. Certain contracts provide for title and risk of loss transfer at the point of destination, in which case revenue is recognized when it arrives at its destination.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
3. Critical and Significant Accounting Policies (Continued)
Coal sales contracts typically contain coal quality specifications. With coal quality specifications in place, the raw coal sold by us to the customer at the delivery point must be substantially free of magnetic material and other foreign material impurities, and crushed to a maximum size as set forth in the respective coal sales contract. Prior to billing the customer, price adjustments are made based on quality standards that are specified in the coal sales contract, such as British thermal unit factor, moisture, ash and sodium content, and can result in either increases or decreases in the value of the coal shipped.
Transportation costs are included in cost of product sold, and amounts we bill to our customers for transportation are included in revenues.
Asset Retirement Obligations and Remediation Costs
We recognize liabilities for asset retirement obligations ("AROs") where we have legal obligations associated with the retirement of long-lived assets. We recognize AROs at fair value at the time the obligations are incurred. The Company's AROs generally are incurred when a mine site is disturbed by mining activities and as the extent of disturbance increases. AROs reflect costs associated with legally required mine reclamation and closure activities, including earthwork, revegetation and demolition and are estimated based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are adjusted for estimated inflation and discounted at an adjusted, risk-free rate. The ARO amount is capitalized as part of the related mining property upon initial recognition and is included in depreciation and depletion expense using the units-of-production method based on proven and probable reserves. As changes in estimates occur (such as changes in estimated costs or timing of reclamation activities resulting from mine plan revisions), the ARO liability and related asset are adjusted to reflect the updated estimates. Increases in ARO liabilities resulting from the passage of time are recognized as accretion expense by applying the adjusted, risk-free rate that existed when the liability was initially measured to the amount of the liability at the beginning of the period. Other costs related to environmental remediation are charged to expense as incurred. When the reduction of the asset retirement obligation exceeds the carrying amount of the related asset retirement cost, the adjustment is recorded as a reduction of depletion expense.
We periodically update estimates of cash expenditures to meet each mine's reclamation requirements and we adjust the ARO in accordance with U.S. GAAP, which generally requires a measurement of the present value of any increase in estimated reclamation costs using an adjusted, risk-free interest rate based on U.S. Treasury bonds with a maturity similar to the expected remaining life of the mine. Adjustments to the ARO for decreases in the estimated amount of reclamation costs are measured using an adjusted, risk-free interest rate as of the date of the initial recognition of the ARO.
Coal Reserves, Mineral Rights, and Federal Coal Leases
We state our coal reserves at cost, less accumulated depletion. The cost of coal reserves includes, where applicable, the present value of payments required under leases that convey mineral rights, based on our estimate of the credit-adjusted, risk-free interest rate at inception of the lease. We compute depletion of coal reserves and mineral rights using the units-of-production method based on proven
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
3. Critical and Significant Accounting Policies (Continued)
and probable reserves. Coal reserves and mineral rights are included in land, improvements and mineral rights in property, plant and equipment, net.
Upon the award date of federal coal leases, pursuant to which payments are required to be paid in equal annual installments, we recognize an asset for the related mineral rights in property, plant and equipment and a corresponding liability for our future payment obligations in long-term debt. The amount recognized as an asset is the sum of the initial installment due at the effective date of the lease and the amount recognized in long-term debt, which reflects the present value of the remaining installments. We determine the present value of the remaining installments using an estimate of the credit-adjusted, risk-free rate that reflects our credit rating. Interest is recognized over the term of the lease based on the imputed interest rate that was used to determine the initial long-term debt amount on the effective date. Such interest may be capitalized while activities are in progress to prepare the acquired coal reserves for mining. The mineral rights asset recorded at the effective date is eventually recognized in depreciation and depletion expense using the units-of-production method over the period the related coal reserves are mined.
Income Taxes
We account for income taxes using a balance sheet approach in accordance with U.S. GAAP. Deferred income taxes are provided for temporary differences arising from differences between the financial statement and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates expected to be in effect when the related taxes are expected to be paid or recovered. A valuation allowance is established if it is more likely than not that a deferred tax asset will not be realized. In determining the appropriate valuation allowance, we consider projected realization of tax benefits based on expected levels of future taxable income, available tax planning strategies and our overall deferred tax position. We recognize the benefit of uncertain tax positions at the greatest amount that is determined to be more likely than not of being realized. Interest and penalties related to income tax matters are included in income tax expense in the consolidated statements of operations.
Prior to our IPO, we were a member of a consolidated federal tax group and were party to a federal tax sharing agreement with the other members of the consolidated federal tax group. However, for the purposes of our pre-IPO consolidated financial statements, which were prepared on a carve-out basis, our current and deferred income taxes were calculated on a stand-alone income tax return basis. Differences arose as a result of computing our federal income taxes pursuant to the federal tax sharing agreement and on a stand-alone income tax return basis for the carve-out consolidated financial statements. For the year ended December 31, 2008, income taxes recognized in the carve-out consolidated financial statements exceeded income taxes pursuant to the tax sharing agreement by $29.6 million. This amount is presented as a capital contribution within former parent's equity, as the amount will not be paid by us.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
3. Critical and Significant Accounting Policies (Continued)
Tax Agreement Liability
In connection with our IPO structuring transactions and Secondary Offering (see Note 2), we recognized a liability for the estimated, undiscounted amounts that we expect to pay RTEA in future years pursuant to the Tax Receivable Agreement, which we generally refer to as the tax agreement liability. The actual amounts payable under this agreement are determined and paid annually, after CPE Inc. has filed its income tax returns for the prior year. The annual payments are determined based on the difference between (i) CPE Inc.'s actual income tax liability for the prior year, which reflects the effects of the increase in tax basis that resulted from its acquisition of interests in CPE Resources, and (ii) a hypothetical calculation of CPE Inc.'s tax liability that assumes no such increase in tax basis. The required annual payments generally are equal to 85% of the tax savings actually realized as a result of the tax basis increase. Our estimate of the tax agreement liability is based on forecasts of our future income tax payments, with and without the tax basis increase, over the anticipated life of our mining operations and reclamation activities, assuming no additional coal reserves are acquired. The assumptions used in our forecasts are consistent with assumptions used in determining the valuation allowance for our deferred tax assets and in other contemporaneous accounting measurements, such as our annual test of goodwill impairment. We revise our estimated tax agreement liability annually in conjunction with our annual life-of-mine planning process, which typically takes place in the third quarter, or more frequently when there are significant changes in circumstances, such as the acquisition of additional coal reserves. Future changes in our estimated tax agreement liability will be recognized in other expense in our consolidated statement of operations. See Note 17 for more information about the Tax Agreement Liability.
Significant Accounting Policies
Cash and Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Money market funds that meet all qualifying criteria for a money market fund under the Investment Company Act of 1940 are considered to be cash equivalents.
Restricted Cash
Restricted cash consists of cash and cash equivalents held in accounts that are subject to contractual restrictions on our ability to withdraw funds. We classify restricted cash as a current asset when we have the contractual right and economic ability to withdraw funds from the restricted cash account within one year from the balance sheet date. We may use restricted cash balances to collateralize surety bonds that secure our performance under certain of our reclamation obligations. Our surety bonds permit us to provide cash or letters of credit as collateral. In determining whether we have the ability to withdraw funds from restricted cash accounts, we consider the available capacity under our revolving credit facility, our forecasted cash flows and other relevant information.
Allowance for Doubtful Accounts Receivable
We determine an allowance for doubtful accounts based on the aging of accounts receivable, historical experience and management judgment. We write off accounts receivable against the allowance when we determine a balance is uncollectible and we no longer continue to actively pursue collection of
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
3. Critical and Significant Accounting Policies (Continued)
the receivable. Based on our assessment of the above criteria, there was no allowance for doubtful accounts at December 31, 2010 and 2009.
Inventories, Net
Materials and Supplies
We state materials and supplies at the lower of average cost or net realizable value. We establish allowances for excess or obsolete materials and supplies inventory based on prior experience and estimates of future usage.
Stockpiles and Finished Product ("Coal Inventory")
We state our coal inventory, which consists of coal stockpiles that may be sold in their current condition or may be further processed prior to shipment to a customer, at the lower of average cost or net realizable value. Net realizable value represents the estimated future sales price based on spot coal prices and prices under long-term contracts, less the estimated costs to complete production and bring the product to sale. The cost of coal inventory reflects mining costs incurred up to the point of stockpiling the coal and includes labor, supplies, equipment, applicable operating overhead and depreciation, depletion and amortization related to mining operations.
Property, Plant and Equipment
Plant and Equipment
We state plant and equipment at cost, less accumulated depreciation. Plant and equipment used in mining operations that are expected to remain in service for the life of the related mine are depreciated using the units-of-production method based on proven and probable reserves. Depreciation of other plant and equipment is computed using the straight-line method over the following estimated useful lives:
Capitalization of Interest
We capitalize interest costs on accumulated expenditures incurred in preparing capital projects for their intended use.
Mine Development Costs
We capitalize costs of developing new mines where proven and probable reserves exist. We amortize mine development costs using the units-of-production method based on proven and probable reserves that are associated with the property being developed. Costs may include construction permits and licenses; mine design; construction of access roads, slopes and main entries; and removing overburden and waste materials to access the coal ore body in a new pit prior to the production phase, which commences when saleable coal, beyond a de minimis amount, is produced. Where multiple pits exist at a mining operation, overburden removal costs are capitalized if such costs are for the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
3. Critical and Significant Accounting Policies (Continued)
development of a new area that is separate and distinct from the existing production phase mines. Overburden removal costs that relate to the enlargement of an existing pit are expensed as incurred. Overburden removal costs incurred during the production phase are included as a cost of inventory to be recognized in cost of product sold in the same period as the revenue from the sale of inventory. Additionally, mine development costs include the costs associated with asset retirement obligations. Mine development costs are included in land, improvements and mineral rights in property, plant and equipment, net.
Repairs and Maintenance
We capitalize costs associated with major renewals and improvements. Expenditures to replace or completely rebuild major components of major equipment, which are required at predictable intervals to maintain asset life or performance, are capitalized. These major components are capitalized separately from the major equipment and depreciated according to their own estimated useful life, rather than the estimated useful life of the major equipment. All other costs of repairs and maintenance are charged to expense as incurred.
Exploration Costs
We expense all direct costs incurred in identifying new resources and in converting resources to reserves at development and production stage projects. Exploration costs of $0.2 million, $1.2 million and $1.4 million for the years ended December 31, 2010, 2009 and 2008, respectively, are included in cost of product sold.
Impairment
We evaluate the recoverability of our long-lived assets when events or changes in circumstances indicate that the carrying amount of property, plant and equipment may not be recovered over its remaining service life. An asset impairment charge is recognized when the sum of estimated future cash flows associated with the operation and disposal of the asset, on an undiscounted basis, is less than the carrying amount of the asset. An impairment charge is measured as the amount by which the carrying amount of the asset exceeds its fair value. Fair value is measured using discounted cash flows based on estimates of coal reserves, coal prices, operating expenses and capital costs or by reference to observable comparable transaction or replacement cost data.
Intangible Assets
We state intangible assets at cost, less accumulated amortization. The cost of intangible assets consists of the fair value assigned to favorable long-term coal supply contracts in connection with business combinations and is amortized based on deliveries over the terms of the contracts. Intangible assets are subject to evaluation for potential impairment if an event occurs or a change in circumstances indicates the carrying amount may not be recoverable. No impairment charges were recorded in 2010, 2009, or 2008.
Goodwill
We assess the carrying amount of goodwill for impairment annually during the fourth quarter, or more frequently if an event occurs or circumstances change that would more likely than not reduce the
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
3. Critical and Significant Accounting Policies (Continued)
fair value of a reporting unit below its carrying amount. We assess goodwill for possible impairment using a two-step method in which we compare the carrying amount of each reporting unit to its fair value. If the carrying amount of a reporting unit exceeds its fair value, we perform an analysis to determine the fair values of the assets and liabilities of the reporting unit to determine whether the implied goodwill of that reporting unit has been impaired. We determine the fair value of our reporting units utilizing estimated future discounted cash flows based on estimates of proven and probable reserves, coal prices and operating costs, consistent with assumptions that we believe marketplace participants would use in their estimates of fair value. The carrying amount of our goodwill does not include any accumulated impairment losses.
Pensions and Other Postretirement Benefits
Our employees participate in defined contribution retirement plans, which require us to make contributions based on a percentage of compensation or to match employee contributions, subject to limitations. We recognize compensation expense for our required contributions as incurred.
Prior to our IPO, our employees, which do not include Decker employees, participated in a defined benefit retirement plan sponsored by Rio Tinto America. Periodic costs pertaining to this plan were allocated to us by Rio Tinto America on a basis of projected benefit obligation with respect to financing costs and on the basis of actuarial determinations for current and prior service costs. Our employees ceased to participate in this plan as a result of our IPO, and we have not assumed any pension obligations associated with this plan.
Prior to our IPO, our employees participated in a defined benefit postretirement welfare plan sponsored by Rio Tinto America. This plan provided for retired employees and their beneficiaries and dependents who meet eligibility requirements to receive medical, dental and life insurance benefits, subject to certain cost-sharing features, such as deductibles and coinsurance. We recognized a net periodic postretirement benefit cost for our required contribution to this plan based on actuarial cost data and an allocation from Rio Tinto America. Our employees ceased to participate in this plan; however, we agreed to sponsor, effective January 1, 2010, a new postretirement medical plan that provides retiree medical benefits for our employees. We account for postretirement benefits other than pensions by accruing the costs of benefits to be provided over the employees' period of active service. These costs are determined on an actuarial basis. Our consolidated balance sheets reflect the funded status of postretirement benefits.
Decker's employees participate in a defined benefit retirement plan sponsored by Decker, which is accounted for in accordance with U.S. GAAP requirements for defined benefit pension plans.
Accrued Liabilities
Contingent Liabilities
We account for contingent liabilities related to litigation, claims and assessments based on the specific facts and circumstances and our experience with similar matters. We record our best estimate of a loss when the loss is considered probable and the amount of loss is reasonably estimable. When a loss is probable and there is a range of the estimated loss with no best estimate in the range, we record our estimate of the minimum liability. As additional information becomes available, we revise our estimates as appropriate.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
3. Critical and Significant Accounting Policies (Continued)
Workers' Compensation
For our employees in Wyoming, workers' compensation insurance is provided through a state fund program. We contribute to this program by applying the assessed state rate to gross payroll for the applicable employees, which is adjusted prospectively based on our workers' compensation historical incident rating.
For our employees in Colorado and Montana, workers' compensation insurance is provided under a zero-deductible workers' compensation program, which provides full coverage for any workers' compensation losses, including black-lung claims.
Share-Based Compensation
We measure the cost of share-based employee compensation based on the fair value of the award and recognize that cost over the period during which the recipient is required to provide services in exchange for the award, typically the vesting period. For equity awards, compensation cost is measured based on grant-date fair value of the award. The fair value of certain share-based payment awards is estimated using a Black-Scholes option valuation model. Prior to our IPO, certain of our employees participated in share-based compensation plans sponsored by Rio Tinto. As a result of our IPO, the awards granted by Rio Tinto became vested in accordance with the employee separation provisions contained in the original terms of the awards.
Discontinued Operations
We report items within discontinued operations in the consolidated statements of operations when the operations and cash flows of a particular component (defined as operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity) have been eliminated from our ongoing operations as a result of a disposal transaction, and we will no longer have any significant continuing involvement in the operations of that component. See Note 4 for additional information about discontinued operations.
Segment Information
We review, manage and operate our business as a single operating segment-the production of low sulfur, steam coal from surface mines, located in the Western region of the U.S. within the Powder River Basin ("PRB"), which is sold to electric utilities and industrial customers.
Earnings per Share
We compute basic earnings per share by dividing net income by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed using the weighted-average number of common and potential dilutive common shares outstanding during the period. We apply the treasury stock method to determine potential dilutive common shares related to our stock options and non-vested share awards. We apply the if-converted method to determine potential dilutive common shares related to CPE Resources common membership units that are convertible to CPE Inc. common shares.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. Discontinued Operations
There were no discontinued operations for the year ended December 31, 2010.
Sale of Jacobs Ranch Mine
Effective March 8, 2009, we entered into an agreement to sell our membership interest in Jacobs Ranch Coal LLC, which owned and operated the Jacobs Ranch coal mine, to Arch Coal, Inc. for cash consideration of $761.0 million, subject to certain adjustments as of the closing date. The sale closed on October 1, 2009, resulting in gross sales proceeds of $768.8 million, which were distributed to Rio Tinto America, and a pre-tax gain on sale of $264.8 million. The Jacobs Ranch mine was classified as held for sale and reported as discontinued operations as of March 1, 2009. As a result, the consolidated financial statements report the financial position, results of operations and cash flows of the Jacobs Ranch mine as discontinued operations in all periods presented. Included in Jacobs Ranch mine revenues in the table below are sales to our other subsidiaries of $21.9 million and $17.7 million for the years ended December 31, 2009 and 2008, respectively. Sales of coal to our other subsidiaries continued after the closing date under contracts that terminate upon completion of all required shipments in 2010. We determined that our purchases from the mine after the closing date do not represent significant continuing involvement based primarily on the immateriality of the expected purchases compared to the expected production of the mine and the short duration of the contracts.
Distribution of Colowyo and Uranium Mining Venture
Effective October 7, 2008, RTEA distributed to Rio Tinto America its controlling interests in Colowyo, together with a uranium mining venture undergoing reclamation activities. The consolidated financial statements report the financial position, results of operations and cash flows of the distributed entities as discontinued operations in all periods presented. Subsequent to the distribution date, we provided certain transitional management and administrative support services to the distributed entities on a cost reimbursement basis. These transitional services were concluded in March 2009.
The liabilities of the entities distributed to Rio Tinto America (including amounts payable to RTEA) exceeded the assets of such entities by $130.1 million on the distribution date. In December 2008, RTEA distributed to Rio Tinto America receivables due from the distributed entities totaling $115.2 million. We recorded a $14.9 million net capital contribution in the fourth quarter of 2008 for the amount by which the liabilities of the distributed entities exceeded their assets and the distributed receivables. The assets and liabilities were transferred at their respective carrying amounts as of the dates of distribution. No gain or loss was recognized in connection with the distribution.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. Discontinued Operations (Continued)
Income (loss) from discontinued operations, net of tax, presented in the consolidated statements of operations consists of the following for the years ended December 31 (in thousands):
5. Inventories
Inventories, net consisted of the following at December 31 (in thousands):
Materials and supplies are stated net of an obsolescence allowance of $0.6 million and $1.3 million as of December 31, 2010 and 2009, respectively. We recognized a provision to increase the allowance by $976,000, $973,000 and $356,000, and charged inventory costs to the allowance of $1,709,000, $897,000 and $325,000, for the years ended December 31, 2010, 2009 and 2008, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
6. Property, Plant and Equipment
Property, plant and equipment, net consisted of the following at December 31 (in thousands):
(1)Includes mineral rights of $319.3 million and $295.5 million at December 31, 2010 and 2009, respectively, attributable to areas where the Company was not currently engaged in mining operations and, therefore, the coal reserves are not currently being depleted.
Interest costs capitalized on mine development and construction projects totaled $24.5 million, $15.5 million and $6.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.
In 2010, we recognized an impairment charge of $659,000 for a piece of equipment which we no longer use. The impairment represents an adjustment to the estimated net realizable value that we expect to obtain from the sale of the equipment. In 2009, we recognized an impairment charge of $698,000 for costs incurred on an abandoned time-keeping software project. In 2008, we recognized an impairment charge of $1.01 million for costs incurred on an abandoned production cost efficiency project.
A $3.1 million reduction of the asset impairment charge was recognized in the year ended December 31, 2008, as a result of favorable changes in estimates and resolution of contingencies related to a 2007 asset impairment charge associated with the abandonment of a Rio Tinto system implementation.
7. Intangible Assets
Intangible assets, net consisted of the following at December 31 (in thousands):
At December 31, 2009, acquired long-term coal supply contracts consisted of a contract acquired in 1993 that expired in 2010. The remaining $3.2 million unamortized balance of the contract was fully amortized in 2010.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
7. Intangible Assets (Continued)
In March 2008, a Decker contract was amended to provide for a reduction in the quantities of coal to be supplied during 2009 through 2012 in exchange for a $12.7 million cash payment from the customer in 2009. Upon execution of the amendment, we recognized $6.3 million of revenue, representing our 50% interest in the cash to be received in exchange for the relief of the Company's obligation to supply coal, and amortization expense of $9.2 million, representing the accelerated amortization of our contract rights corresponding to the reduction in coal supply quantities under the amended contract. As a result of changes in the Decker mine plan in the fourth quarter of 2008, which resulted in lower projected cash flows, we evaluated the recoverability of Decker long-lived assets in December 2008 and determined that the remaining carrying amount of the Decker contract was not recoverable. Consequently, we recognized a $4.6 million impairment charge to reduce the carrying amount of our remaining contract rights to its estimated fair value of zero.
8. Investments
Investments are included in other noncurrent assets and have a carrying amount of $9.4 million and $4.5 million at December 31, 2010 and 2009, respectively. Investments at December 31, 2010 and 2009 consist of our 50% equity investment in Venture Fuels Partnership, a coal marketing company.
9. Long-Term Debt
Long-term debt consisted of the following at December 31 (in thousands):
Senior Notes
On November 25, 2009, CPE Resources and its wholly-owned subsidiary, Cloud Peak Energy Finance Corp., issued the 8.25% Senior Notes due 2017 ("2017 Notes") and the 8.5% Senior Notes due 2019 ("2019 Notes"), which we refer to collectively as the Senior Notes, in accordance with Rule 144A of the Securities Act of 1933, as amended. The 2017 Notes and the 2019 Notes each were issued in the aggregate principal amount of $300.0 million, net of original issue discounts of $2.2 million and $2.5 million, respectively, resulting in aggregate proceeds of $595.3 million. The 2017 Notes and 2019 Notes bear interest at fixed annual rates of 8.25% and 8.50%, respectively, and mature on December 15, 2017 and 2019, respectively. There are no mandatory redemption or sinking fund payments for the Senior Notes and interest payments are due semi-annually on June 15 and December 15, which commenced on June 15, 2010. Subject to certain limitations, we may redeem the 2017 Notes by paying specified redemption prices in excess of their principal amount prior to December 15, 2015, or by paying their principal amount thereafter. Similarly, we may redeem the 2019 Notes by paying specified redemption prices in excess of their principal amount prior to December 15, 2017, or by paying their principal amount thereafter.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Long-Term Debt (Continued)
Debt issuance costs of approximately $14.2 million were incurred in connection with the issuance of the Senior Notes. These costs were deferred and are being amortized to interest expense over the respective terms of the Senior Notes using the effective interest method. Unamortized debt issuance costs of $12.8 million and $14.1 million were included in noncurrent other assets at December 31, 2010 and 2009, respectively.
The Senior Notes are jointly and severally guaranteed by all of our existing and future restricted subsidiaries that guarantee our debt under our credit facility. See "Senior Secured Revolving Credit Facility" below. Substantially all of our consolidated subsidiaries, excluding Decker Coal Company in which CPE Resources holds a 50% interest, are considered to be restricted subsidiaries and guarantee the Senior Notes.
The indenture governing the Senior Notes, among other things, limits our ability and the ability of our restricted subsidiaries to incur additional indebtedness and issue preferred equity; pay dividends or distributions; repurchase equity or repay subordinated indebtedness; make investments or certain other restricted payments; create liens; sell assets; enter into agreements that restrict dividends, distributions or other payments from restricted subsidiaries; enter into transactions with affiliates; and consolidate, merge or transfer all or substantially all of their assets and the assets of their restricted subsidiaries on a combined basis.
The approximate fair value of our Senior Notes was $650.3 million at December 31, 2010. The fair value of the Senior Notes is based on market quoted prices as of December 31, 2010.
Senior Secured Revolving Credit Facility
Concurrently with the offering of the Senior Notes, we entered into a $400.0 million senior secured revolving credit facility, or Credit Facility, with a syndicate of lenders, the full amount of which is available for use in connection with loans or the issuance of letters of credit. The Credit Facility may be expanded at our request, subject to certain conditions and to the extent lenders are willing to extend additional commitments, up to an additional $50.0 million. Our obligations under the Credit Facility are supported by a guarantee by certain of our restricted subsidiaries. The Credit Facility matures on December 16, 2013. As of December 31, 2010, letters of credit totaling $10.5 million and no cash borrowings were outstanding under the Credit Facility. The letters of credit are used as collateral to secure our obligations to reclaim lands used for mining. See Note 17.
Lender fees and costs of $15.9 million were incurred in connection with the execution of the Credit Facility. These costs are being amortized to interest expense over the term of the Credit Facility using the straight-line method. Unamortized fees and costs of $11.7 million and $15.5 million were included in noncurrent other assets at December 31, 2010 and 2009.
Loans under the Credit Facility bear interest at the greater of the LIBOR or 2.50%, plus an applicable margin based on our credit rating of between 3.25% and 4.25% (4.00% at December 31, 2010). At our option, the interest rate on loans under the Credit Facility may be based on an alternative base rate of at least 3.50%, and the applicable margins over such alternative base rate are 1.00% less than the applicable margin for LIBOR loans. We are required to pay the lenders a commitment fee of 0.75% per year on the unused amount of the Credit Facility. Letters of credit issued under the Credit Facility, unless drawn upon, bear interest at the applicable margin for LIBOR loans from the date at which they are issued. In addition, in connection with the issuance of a letter of
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Long-Term Debt (Continued)
credit we are required to pay the issuing bank a fronting fee of 0.25% plus additional customary administrative fees and expenses.
Our obligations under the Credit Facility are secured by substantially all of our assets and substantially all of the assets of certain of our subsidiaries, subject to certain permitted liens and to customary exceptions for similar coal financings. We are subject to financial maintenance covenants based on EBITDA (which is defined in the Credit Facility and is not the same as EBITDA or Adjusted EBITDA presented elsewhere in our consolidated financial statements) requiring us to maintain defined minimum levels of interest coverage and providing for a limitation on our total and first lien senior secured debt leverage ratios. Specifically, the Credit Facility requires us to maintain a ratio of EBITDA to consolidated net cash interest expense equal to or greater than 2.75 to 1, a ratio of funded debt to EBITDA equal to or less than 3.5 to 1, and a ratio of first lien senior secured debt to EBITDA equal to or less than 1.5 to 1 as long as the Credit Facility is in effect.
Our Credit Facility also requires us to comply with non-financial covenants that restrict certain activities at both the corporate and subsidiary levels and contains customary events of default with customary grace periods and thresholds. These covenants include restrictions on our ability to incur additional debt and pay dividends, among other restrictive covenants. Our ability to access the available funds under the Credit Facility may be impaired in the event that we do not comply with the covenant requirements or if we default on our obligations under the agreement. In addition, under the terms of the Credit Facility, a change in control of Cloud Peak Energy Inc. or CPE Resources would result in an automatic event of default and, unless waived by the required lenders, would result in all obligations under the Credit Facility to become immediately due and payable. At December 31, 2010, we were in compliance with the covenants contained in our Credit Facility.
RTA Facility
Prior to its termination in 2008, our credit facility with Rio Tinto America (the "RTA Facility") allowed us to borrow up to $800.0 million from Rio Tinto America with no specified maturity date. Borrowings under the RTA Facility were subject to interest, payable quarterly, calculated on the daily average borrowings outstanding during the quarter at a rate equal to the average 3 month U.S. dollar LIBOR plus a margin of 1.5%. Interest cost related to the RTA Facility was $16.8 million for the year ended December 31, 2008. As of December 31, 2007, $37.4 million of accrued interest on the RTA Facility was converted to principal. Effective September 24, 2008, the RTA Facility was terminated and the then outstanding balance was converted to equity. The total outstanding principal and accrued interest amount at the effective date of the termination of the RTA Facility of $547.4 million is reflected as a capital contribution in the consolidated statement of equity for the year ended December 31, 2008.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Long-Term Debt (Continued)
Future Maturities
Aggregate future maturities of long-term debt as of December 31, 2010 are as follows (in thousands):
Interest expense under financing arrangements, net of amounts capitalized, totaled $46.9 million, $6.0 million and $20.4 million for the years ended December 31, 2010, 2009 and 2008, respectively.
10. Other Long-Term Obligations
Long-term obligations consisted of the following at December 31 (in thousands):
Federal Coal Leases
The Company's federal coal leases, as reflected in the consolidated balance sheets, consist of discounted obligations payable to the Bureau of Land Management of the U.S. Department of the Interior under four leases, each of which requires five equal annual payments, as follows (in thousands):
The Company recognizes imputed interest on federal coal leases based on an estimate of the credit-adjusted, risk-free rate reflecting the Company's estimated credit rating at the inception of the lease. Imputed interest for the years ended December 31, 2010, 2009 and 2008 was $11.7 million, $14.2 million and $7.9 million, respectively, of which, $10.8 million, $14.1 million and $5.8 million, respectively, was capitalized as we prepared to mine the related coal deposits.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
10. Other Long-Term Obligations (Continued)
Other
Other long-term obligations consists of obligations incurred in connection with the acquisitions of land and mineral rights. At December 31, 2010 and 2009, we had $8.1 million and $9.3 million of purchase obligations with parties other than the BLM of which $4.8 million and $4.5 million are current as of December 31, 2010 and 2009, respectively. These bear interest at rates ranging from 6% to 8%.
The approximate fair value of our federal coal lease obligations was $127.6 million at December 31, 2010. The fair value estimates for the federal coal leases were determined by discounting the remaining lease payments using a current estimate of the credit-adjusted, risk-free interest rate that is based on the Company's current credit standing.
11. Asset Retirement Obligations
Changes in the carrying amount of the Company's asset retirement obligations were as follows (in thousands):
The above amounts exclude $5.9 million and $6.5 million of concurrent reclamation for the years ended December 31, 2010 and 2009, respectively. The revisions to estimated cash flows pertain to revisions in the estimated amount and timing of legally required reclamation activities throughout the lives of the respective mines and reflect changes in estimates of closure volumes, disturbed acreages and third-party unit costs as of December 31, 2010 and 2009. Adjustments to AROs resulting from such revisions generally result in a corresponding adjustment to the related asset retirement cost in property, plant and equipment, net.
In 2008, a change in the timing of reclamation activities for one of our mines resulted in a reduction in the asset retirement obligation that exceeded the carrying amount of the related asset retirement cost by $4.7 million ($3.0 million after tax) and was recognized as a reduction of depreciation and depletion expense in the period.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. Employee Benefit Plans
Our consolidated statements of operations include expenses in connection with employee benefit plans sponsored by Cloud Peak Energy (subsequent to our IPO) and Rio Tinto America (prior to our IPO), as follows for the years ended December 31 (in thousands):
Cloud Peak Energy Plans
Defined Contribution Retirement Plans
In connection with our IPO, we established the Cloud Peak Energy 401(k) Plan and Profit Sharing Plan in order to facilitate the accumulation of retirement savings for our employees, which do not include Decker employees. Our employees may elect to contribute a portion of their salary on a pre-tax basis to their account in the 401(k) Plan and we match the employee contributions up to 6% of eligible compensation. We also contribute an additional 6% of eligible compensation to employee accounts under the Profit Sharing Plan. All contributions are fully vested at the date of contribution.
Retiree Medical Plan
In connection with our IPO, we agreed to establish a plan to provide certain postretirement medical benefits to eligible employees, which does not include Decker employees (the "Retiree Medical Plan"). Employees who are 55 years old and have completed ten years of service with the Company generally are entitled to receive benefits under the Retiree Medical Plan, except for employees who were eligible at the date of our IPO to receive benefits under the Rio Tinto America retiree medical plan and elect to receive such benefits. As required by an agreement between Rio Tinto America and us in connection with the IPO, the retiree medical plan grants credit for service rendered by our employees to Rio Tinto America prior to the IPO.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. Employee Benefit Plans (Continued)
Net periodic postretirement benefit costs included the following components:
We recognized a $16.6 million liability as of November 19, 2009, for our accumulated postretirement benefit obligation ("APBO") under the Retiree Medical Plan. The initial APBO amount reflects the cost of certain benefits attributable to services rendered by our employees prior to the initiation of the Retiree Medical Plan. The APBO for prior service cost was allocated between the controlling and noncontrolling interests in CPE Resources and charged to accumulated other comprehensive loss (see Note 14). These amounts will be recognized in net periodic postretirement benefit cost over the remaining period prior to the date the employees become eligible to receive benefits. At the time that we recognized the liability we classified $1.3 million of the liability as current.
At December 31, 2009, we remeasured and adjusted the liability for the APBO to $16.4 million, of which $20,000 is included in current liabilities and $16.4 million is included in noncurrent other liabilities in our consolidated balance sheet at December 31, 2009. The net decrease of $236,000 in the APBO for the period ended December 31, 2009, is attributable to the recognition of a $595,000 pre-tax actuarial gain in other comprehensive income, partially offset by the recognition of service cost of $252,000 and interest cost of $107,000 in our consolidated statement of operations.
At December 31, 2010, we remeasured and adjusted the liability for the APBO to $23.3 million, of which $37,000 is included in current liabilities and $23.2 million is included in noncurrent other liabilities in our consolidated balance sheet at December 31, 2010. The net increase of $6.9 million in the APBO for the period ended December 31, 2010, is attributable to $2.3 million in current period service cost, $1.0 million in interest costs and $3.6 million in increased costs associated with changes in actuarial assumptions.
We used the following assumptions in the measurement of the APBO:
To determine the discount rate, we matched our cash projections against the Citigroup Pension Discount Curve. Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point increase in the assumed health care cost trend would increase net periodic postretirement benefit cost and the APBO by $492,865 and $3.0 million, respectively, and a one-percentage-point decrease in the rate would decrease net periodic postretirement benefit cost and the APBO by $408,361 and $2.5 million, respectively, as of December 31, 2010.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. Employee Benefit Plans (Continued)
Our estimated future benefit payments under the Retiree Medical Plan, which are net of estimated employee contributions and reflect expected future service, are as follows for the years ended December 31 (in thousands):
Rio Tinto America Plans
Defined Contribution Retirement Plans
Prior to our IPO, we were a participating employer in two defined contribution plans sponsored by Rio Tinto America. We were required to contribute to these plans based on eligible employee compensation and employee contribution matching requirements. Employees of Decker were not included in these plans.
Defined Benefit Plans
Prior to our IPO structuring transactions, our employees, which do not include Decker employees, participated in a defined benefit pension plan and a retiree medical plan sponsored by Rio Tinto America. We made contributions to the pension plan as determined by consulting actuaries based upon the applicable regulatory funding standard and made contributions to the retiree medical plan as benefits were paid. We recognized benefit costs in excess of our contributions on a carve-out basis, based on an allocation of net periodic pension cost and net periodic postretirement benefit cost, as determined in accordance with U.S. GAAP. Our liabilities for costs incurred under these plans were recognized in due to related parties and were cancelled in connection with our IPO structuring transactions (see Note 2). For the year ended December 31, 2008, we recorded a charge to former parent's equity of $687,000, net of tax, in connection with a change in the measurement date for plan assets and benefit obligations.
Decker Pension Plan
Decker's employees participate in a defined benefit retirement plan sponsored by Decker. This plan does not have a material impact on our consolidated financial position, results of operations or cash flows. Our share of the funded status of the plan is reported in noncurrent other liabilities and was $2.9 million and $2.5 million at December 31, 2010 and 2009, respectively. Other comprehensive income or loss includes certain actuarial gains and losses that are reflected in the funded status of the plan, but have not been recognized in periodic benefit cost.
13. Income Taxes
Our income from continuing operations before income tax provision and earnings (losses) from unconsolidated affiliates is earned solely in the U.S. For periods prior to our IPO, our consolidated financial statements reflect income taxes recognized by RTEA. See "Initial Public Offering, Related
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. Income Taxes (Continued)
IPO Structuring Transactions, and Secondary Offering" in Note 2. RTEA was a member of an affiliated federal tax group and was party to a federal income tax sharing agreement with the other members of the affiliated federal income tax group. However, for the purposes of our consolidated financial statements, which were prepared on a carve-out basis, RTEA's current and deferred taxes were calculated on a stand-alone separate return basis. RTEA provided income taxes on substantially all pre-tax income reported in our consolidated financial statements for such pre-IPO periods. For periods following our IPO, CPE Inc. is required to file a separate federal corporate income tax return and recognizes income taxes on its pre-tax income, which for periods before the Secondary Offering has consisted solely of its share (approximately 51%) of CPE Resources pre-tax income. For periods following the Secondary Offering, CPE Inc. recognizes income tax expense on 100% of pretax income. CPE Resources is organized as a limited liability company and generally is not subject to income taxes, although several corporate subsidiaries of CPE Resources file separate corporate income tax returns and may incur minor amounts of income tax or may incur losses which cannot benefit other entities included in the consolidated financial results. Because CPE Resources generally is not a taxable entity, our consolidated financial statements do not reflect any income taxes on pre-tax income attributable to the noncontrolling interest in CPE Resources that existed before our Secondary Offering.
The income tax provision (benefit) for continuing operations consisted of the following for the years ended December 31 (in thousands):
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. Income Taxes (Continued)
The tax effects of temporary differences that result in deferred tax assets and deferred tax liabilities for continuing operations consisted of the following at December 31 (in thousands):
At December 31, 2009 CPE Inc.'s principal deferred tax asset relates to its partnership investment in CPE Resources, which reflects an increase in tax basis in connection with our IPO structuring transactions. After the Secondary Offering, CPE Resources is no longer a partnership for tax purposes and CPE Inc. is required to report differences between tax bases of assets and liabilities and the financial statement carrying amount of these items individually. CPE Inc. also has recognized a deferred tax asset for payments it expects to make pursuant to the Tax Receivable Agreement with RTEA, which is recognized as a liability in our consolidated financial statements. Included in our other deferred tax assets are net operating loss carryforwards of $7.8 million that expire in 2029 and 2030 and AMT credits of $2.7 million that do not expire.
Net deferred income tax assets related to continuing operations are classified in the consolidated balance sheets at December 31 as follows (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. Income Taxes (Continued)
The future realization of deferred income tax assets that resulted from the increased tax basis arising from the IPO and the Secondary Offering depends on the existence of sufficient future taxable income. Based on our consideration of CPE Resources' historical operations, current forecasts of taxable income over the remaining lives of our mines, the availability of tax planning strategies, and other factors, we determined that $162.5 million of the potential tax benefits are more likely than not to be realized at the statutory federal and state income tax rates. Accordingly, we have provided a $94.6 million valuation allowance to reduce our deferred tax assets to the amount that we determined is more likely than not to be realized.
The effective tax rate for our continuing operations is reconciled to the U.S. federal statutory income tax rate for the years ended December 31 as follows:
The effective tax rate for 2010 reflects a reduction related to the noncontrolling interest in the pre-tax income of CPE Resources for the period before the Secondary Offering, for which no income taxes were recognized in the consolidated statement of operations.
14. Equity and Comprehensive Income
Immediately prior to our IPO structuring transactions, RTEA and an affiliate held 60,000,000 common membership units in CPE Resources. See "Initial Public Offering, Related IPO Structuring Transactions, and Secondary Offering" in Note 2. In connection with our IPO, we purchased 30,600,000 of the common membership units from RTEA, which represented 51% of the outstanding units. The CPE Resources limited liability company agreement, as amended, requires that there must be a one-to-one ratio between the number of common membership units held by CPE Inc. and the number of shares of CPE Inc. common stock issued and outstanding and not held in treasury.
Therefore, when we issue restricted shares pursuant to the 2009 Cloud Peak Energy Long Term Equity Incentive Plan or if options issued under the plan are exercised and new shares are issued, CPE Inc. acquires additional common membership units in order to maintain the one-to-one ratio. Any time that those restricted shares are forfeited; they are cancelled along with the related membership units. CPE Inc. is required to contribute any cash consideration received for issued shares, net of applicable withholding taxes, to CPE Resources. We issued 849,402 shares of restricted stock on our IPO date and subsequently cancelled 400 shares due to forfeitures (See Note 15). Further stock activity
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14. Equity and Comprehensive Income (Continued)
resulted in a net increase of the total common membership units issued and outstanding to 60,849,002 at December 31, 2009.
Allocations of CPE Resources' net income or net losses are made at the end of each fiscal quarter pro rata based on the number of common membership units owned by each member, as compared to the total number of common membership units outstanding at the time of the allocation. In connection with the Secondary Offering, we exchanged 29,400,000 shares of common stock for the common membership units of CPE Resources held by Rio Tinto and completed the Secondary Offering resulting in a divesture of 100% of Rio Tinto's holdings in Cloud Peak Energy. As CPE Inc. is the 100% holder of all membership units subsequent to the Secondary Offering, all CPE Resources income is now allocated to CPE Inc.
Comprehensive income includes net income and other comprehensive income arising from activity related to our defined benefit employee benefit plans (see Note 12). The following table summarizes the allocation of total comprehensive income between the controlling and noncontrolling interests for the year ended December 31, 2010 (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14. Equity and Comprehensive Income (Continued)
The following table summarizes the allocation of total comprehensive income between the controlling and noncontrolling interests for the year ended December 31, 2009 (in thousands):
The following table summarizes the noncontrolling interest share of CPE Resources' net income (in thousands):
Prior to the Secondary Offering, RTEA and its affiliate had the right to redeem any or all of their common membership units at a per unit redemption price equal to the volume-weighted-average price of a share of CPE Inc. common stock for the ten previous trading days prior to redemption notice being given. CPE Inc. had the right to assume those units by either paying the redemption price noted above in cash, by issuing to RTEA or its affiliate the same number of shares of its common stock as common membership units being redeemed, or a combination of both. As a result of the Secondary Offering, CPE Inc. holds 100% of the common membership units.
15. Share-Based Compensation
Prior to our IPO, certain of our employees participated in share-based compensation plans sponsored by Rio Tinto. In connection with our IPO, we adopted the Cloud Peak Energy Inc. 2009 Long Term Incentive Plan, or LTIP, which permits awards to our employees, which do not include Decker employees, and eligible non-employee directors. The LTIP allows for the issuance of
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. Share-Based Compensation (Continued)
share-based compensation in the form of restricted stock, restricted stock units, options, stock appreciation rights, dividend equivalent rights, performance awards and share awards. The LTIP authorizes a pool of 3.4 million shares of our common stock for issuance in connection with share-based awards.
Total share-based compensation expense recognized primarily within selling, general and administrative expenses in our consolidated statements of operations was as follows for the years ended December 31 (in thousands):
As of December 31, 2010, the total unrecognized compensation cost related to nonvested awards was $18.2 million, which is expected to be recognized over 1.9 years.
Restricted Stock
In connection with our IPO, on November 20, 2009, we granted restricted stock under the LTIP to substantially all of our employees and directors. Generally, the related agreements provide that restricted stock issued will fully vest on the third anniversary of the grant date. However, the restricted stock will pro-rata vest sooner if a grantee terminates employment with or stops providing services to the Company because of death, disability, redundancy or retirement. The restricted stock will fully vest if an employee is terminated without cause within two years after a change in control occurs (as such term is defined in the LTIP).
A summary of restricted stock award activity is as follows (in thousands):
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. Share-Based Compensation (Continued)
Non-Qualified Stock Options
In connection with our IPO, on November 20, 2009, we granted non-qualified stock options under the LTIP to certain employees. Generally, the agreements provide that any option awarded will become exercisable in three years. However, the option will become pro-rata exercisable sooner if a grantee terminates employment because of death, disability, redundancy or retirement. The option award will fully vest if an employee is terminated without cause within two years after a change in control occurs (as such term is defined in the LTIP). No option can be exercised more than ten years after the date of grant. Each award will be forfeited if the grantee terminates employment with or stops providing services to us for any reason other than those reasons noted above.
A summary of non-qualified stock option activity is as follows (in thousands):
We used the Black-Scholes option pricing model to determine the fair value of stock options. Determining the fair value of share-based awards requires judgment, including estimating the expected term that stock options will be outstanding prior to exercise and the associated volatility. As we have no historical exercise history, expected option life assumptions were developed using the simplified method as outlined in Topic 14, Share-Based Payment, of the Staff Accounting Bulletin Series. We utilized U.S. Treasury yields as of the grant date for our risk-free interest rate assumption, matching the treasury yield terms to the expected life of the option. We utilized a 6.5-year peer historical lookback to develop our expected volatility.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. Share-Based Compensation (Continued)
The assumptions used to estimate the fair value of options granted on March 3, 2010 and on November 20, 2009 are as follows (dollar amount in thousands):
Rio Tinto Plans
Prior to our IPO, certain of our employees participated in Rio Tinto share-based compensation plans. As a result of our IPO, the awards granted by Rio Tinto became vested, in full or on a pro-rata basis, in accordance with the employee separation provisions contained in the original terms of the awards. Our share-based compensation expense for the year ended December 31, 2009 includes $936,000 as a result of the accelerated vesting of the Rio Tinto awards. Rio Tinto retained the obligation to settle the vested awards with our employees. As a result of our IPO, we reversed a $1.3 million accrued liability for the fair value of certain awards to be settled in cash and adjusted former parent's equity to reflect Rio Tinto's assumption of this liability. See "Initial Public Offering, Related IPO Structuring Transactions, and Secondary Offering" in Note 2.
16. Earnings Per Share
Prior to our IPO on November 19, 2009, our parent company and predecessor for financial reporting purposes was RTEA. For all periods presented in these consolidated financial statements, RTEA had one share of common stock outstanding. In anticipation of our IPO, RTEA contributed substantially all of its assets and liabilities associated with our coal business to CPE Resources. The limited liability company agreement for CPE Resources was amended in connection with our IPO to increase the number of its common membership units to 60,000,000 units and to require a one-to-one ratio between the number of common membership units held by CPE Inc. and the number of outstanding shares of CPE Inc. common stock. Consequently, CPE Inc.'s acquisition of a 51% interest in CPE Resources resulted in the transfer of 30,600,000 common membership units to CPE Inc. and the issuance of 30,600,000 shares of common stock to the public. We consider the effect of the equity restructuring transactions that occurred in connection with our IPO to be substantially similar to a stock split, where one share of RTEA stock, which prior to our IPO represented 100% ownership of the business of CPE Resources, became equivalent to 60,000,000 common membership units in CPE Resources. Pursuant to the one-to-one ratio requirements, CPE Inc. would have been required to have 60,000,000 shares of common stock outstanding if it had owned the 100% interest in CPE Resources that was held by RTEA, as former parent, prior to our IPO. Accordingly, we assume that 60,000,000 shares of common stock were outstanding during periods prior to our IPO for purposes of calculating basic and diluted earnings per share.
On December 15, 2010, Cloud Peak Energy Inc. priced the Secondary Offering of 29,400,000 shares of its common stock on behalf of Rio Tinto. In connection with the Secondary Offering, we
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
16. Earnings Per Share (Continued)
exchanged 29,400,000 shares of common stock for the common membership units of CPE Resources held by Rio Tinto and completed the Secondary Offering, resulting in a divestiture of 100% of Rio Tinto's holdings in CPE Resources. As a result of this transaction, CPE Resources is now a wholly-owned subsidiary of Cloud Peak Energy Inc.
The table below summarizes the calculation of basic earnings per share for the years ended December 31, (in thousands, except per share amounts):
There were no dilutive potential common shares prior to our IPO. Following our IPO, dilutive potential common shares include restricted shares and options issued under the LTIP (see Note 15) and common shares that may be issued in exchange for CPE Resources common membership units held by Rio Tinto members (see Note 14). We apply the treasury stock method to determine dilution from restricted shares and options, and apply the if-converted method to determine dilution from the exchange of common membership units. In applying the if-converted method, we assumed that the Rio Tinto members have exchanged all of their membership units in CPE Resources for an equivalent number of shares of CPE Inc. common stock. In this calculation, we increased the numerator to include CPE Resources income attributable to the noncontrolling interest and decreased the numerator to reflect the additional income tax expense that results from the attribution of additional CPE Resources income to CPE Inc.'s controlling interest in CPE Resources. The calculation of such additional income tax expense reflects our combined federal and state statutory rate of 36%.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
16. Earnings Per Share (Continued)
The following table summarizes the calculation of diluted earnings per share for the years ended December 31, (in thousands, except per share amounts):
For the year ended December 31, 2010, 877,933 restricted shares and 1,032,495 options outstanding under the LTIP were excluded from the diluted earnings per share calculation because they were anti-dilutive. For the year ended December 31, 2009, 849,002 restricted shares and 1,011,951 options outstanding under the LTIP were excluded from the diluted earnings per share calculation because they were anti-dilutive.
17. Commitments and Contingencies
Commitments
Operating Leases
We occupy various facilities and lease certain equipment under various lease agreements. In April 2010, we entered into a lease agreement for an office in Broomfield, Colorado. The lease commenced in August 2010 and has an initial term of 126 months (10.5 years). Total base rent, including estimated operating expenses, for the entire initial term of the lease is $8.1 million, resulting in an average annual rent expense of approximately $770,000. This new lease agreement replaced our prior sublease of office space in Greenwood Village, Colorado (see Note 18).
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. Commitments and Contingencies (Continued)
The minimum rental commitments under non-cancelable operating leases, with lease terms in excess of one year subsequent to December 31, 2010, are as follows (in thousands):
Rental expense for the years ended December 31, 2010, 2009 and 2008, was $1.2 million, $2.2 million and $1.4 million, respectively.
Purchase Commitments
As of December 31, 2010, we had outstanding capital purchase commitments of $13.1 million and coal purchase commitments of $10.7 million. The coal purchase commitments will be utilized for coal sales made to a customer under the terms of a coal supply agreement that terminates upon completion of all required shipments in 2011.
In April 2008, we entered into an agreement to purchase land adjacent to our Antelope mine, whereby the seller may require us to pay a purchase price of up to $23.7 million which will close between April 2013 and April 2018.
Tax Receivable Agreement
We have recognized a $190.1 million undiscounted liability for our estimated payments to RTEA under the Tax Receivable Agreement, of which $18.2 and $171.9 million is classified as current and noncurrent, respectively, as of December 31, 2010. The estimated liability is based on forecasts of future taxable income over the anticipated life of our mining operations and reclamation activities, assuming no additional coal reserves are acquired. The assumptions used in our forecasts are subject to substantial uncertainty about our future business operations and the actual payments that we are required to make under the Tax Receivable Agreement could differ materially from our estimates. Based on our estimates as of December 31, 2010, we expect to make payments of $18.2 in 2010 and payments averaging approximately $24.5 million during 2012 to 2015. CPE Inc. is obligated to make these payments and expects to obtain funding for these payments by causing CPE Resources to distribute cash to its owner, CPE Inc.
During the quarter ended September 30, 2010, CPE Inc. completed its 2009 federal income tax return filing process, which included a final determination of the amount of the increased tax basis in CPE Inc.'s share of CPE Resources's assets recorded as a result of the IPO structuring transactions. As a result, the initial liabilities CPE Inc. expected to owe under the Tax Receivable Agreement based on its operating plans at the time of the IPO decreased, resulting in a $2.4 million credit to retained earnings as of September 30, 2010.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. Commitments and Contingencies (Continued)
Additionally, in the third quarter CPE Inc. completed its annual update of its most recent operating plans and to its resulting estimated future taxable income. This resulted in an increase in the estimated liability due to Rio Tinto under the Tax Receivable Agreement, resulting in a $19.7 million charge to non-operating income for the year ended December 31, 2010. Related adjustments of $5.4 million to the net value of deferred tax assets are recorded through income tax expense. These charges are solely attributable to Cloud Peak Energy Inc., the controlling interest.
During the quarter ended December 31, 2010, CPE Inc. completed the Secondary Offering and, as a result, we recognized an additional $123.6 million liability for the estimated, undiscounted amounts that we expect to pay RTEA pursuant to the Tax Receivable Agreement. This adjustment does not result in a charge to our statement of operations, but rather as an adjustment to our retained earnings.
CPE Inc.'s payments under the Tax Receivable Agreement would be greater if CPE Inc. generates income significantly in excess of its current estimated future taxable income over the anticipated life of its mines, for example, because CPE Inc. acquires additional LBAs beyond its existing LBAs and, as a result, CPE Inc. realizes the full tax benefit of such increased tax basis (or an increased portion thereof). Required payments under the Tax Receivable Agreement also may increase or become accelerated as a result of certain asset transfers outside the ordinary course of business, a change in control of CPE Resources, or a default by CPE Inc.
Contingencies
Litigation
MMS Litigation-Decker Mine
The Minerals Management Service, or MMS, a federal agency with responsibility for collecting royalties on coal produced from federal coal leases, issued two disputed assessments against Decker Coal Company: one for coal produced from 1986-1992, and the other for coal produced from 1993-2001. Both assessments concern coal sold by Decker to Big Horn Coal Company, or Big Horn, and Black Butte Coal Company, or Black Butte, and in turn resold by those entities to Commonwealth Edison Company to satisfy requirements under long-term contracts between those entities and Commonwealth Edison. The MMS maintained that Decker's royalties should not be based on the prices at which Decker actually sold coal to Big Horn and Black Butte because MMS did not believe those prices represented the results of arm's length negotiation. MMS based this conclusion on the facts that those entities were both affiliates of KCP, Inc., formerly known as Kiewit Coal Properties, Inc., which is also a 50% owner of Decker, and that the sales were contingent on Big Horn's and Black Butte's ability to resell the coal to Commonwealth Edison, which did not leave Big Horn and Black Butte at market risk. Instead, the MMS assessed Decker's royalties based on the higher prices set under Big Horn's and Black Butte's separate long-term contracts with Commonwealth Edison.
With respect to the period 1986-1992, the MMS assessment did not contain a specific dollar amount. Decker appealed the assessment through the administrative process with the MMS and that appeal was unsuccessful. A further appeal was filed before the United States District Court for the District of Montana. In March 2009, the District Court set aside the MMS assessment and entered judgment for Decker ("Decker I"). The MMS did not appeal the ruling.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. Commitments and Contingencies (Continued)
With respect to the period 1993-2001, the MMS assessed approximately $7.5 million plus interest, which was estimated to be approximately $11 million inclusive of interest. Decker appealed the MMS assessment through the administrative process with the MMS and that appeal was unsuccessful. A further appeal was filed before the United States District Court for the District of Montana. In February 2010, the District Court vacated the administrative order from the Interior Board of Land Appeals affirming the MMS assessment. The District Court remanded the case to the MMS for further review and noted that the remand would not unduly prejudice Decker in light of the District Court's opinion in Decker I. There is no MMS assessment currently pending against Decker for the 1993 - 2001 period.
We have not accrued a liability in our consolidated financial statements with respect to this matter as any potential losses are not considered to be probable and reasonably estimable. If the MMS issues a new assessment for the 1993 - 2001 period, Decker believes it will have substantive challenges to any such assessment in light of the District Court's decision in Decker I. Decker also believes that it has contractual price escalation protection from any increased assessments for 1993-2001; and that, in addition, Commonwealth Edison has indemnified Black Butte with respect to the 1993-2001 assessment, and that in furtherance of that obligation, Commonwealth Edison or its parent company, Exelon Generation, Inc., has therefore agreed to indemnify Decker directly for such matters. If a new assessment is issued by the MMS for the 1993 - 2001 period and is upheld and the indemnities and/or price protections were ultimately not available to Decker, the resulting Decker liability could be material. As a result of our 50% ownership interest in Decker, our financial results could in turn be materially adversely affected. We consider Decker's conclusions to be reasonable; however, we have not relied upon Decker's conclusions in reaching our decision that any potential losses are not considered probable and reasonably estimable.
Caballo Coal Company Litigation-Spring Creek
In September 2009, Caballo Coal Company, or Caballo, a subsidiary of Peabody Energy Corporation, commenced an action in Wyoming state court against Spring Creek Coal Company, or Spring Creek, our wholly-owned subsidiary, asserting that Spring Creek repudiated its allegedly remaining obligation under a 1987 agreement to purchase an additional approximately 1.6 million tons of coal, for which it seeks unspecified damages. Spring Creek believes that it has meritorious defenses to the claim, including that Caballo breached the agreement by failing to make required deliveries in 2006 and 2007. Spring Creek also believes that it has meritorious counterclaims against Caballo. If, however, the case was determined in an adverse manner to us, the payment of any judgment could be material to our results of operations.
Other Legal Proceedings
We are involved in other legal proceedings arising in the ordinary course of business and may become involved in additional proceedings from time to time. We believe that there are no other legal proceedings pending that are likely to have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Nevertheless, we cannot predict the impact of future developments affecting our claims and lawsuits, and any resolution of a claim or lawsuit or an accrual within a particular fiscal period may adversely impact our results of operations for that period. In addition to claims and lawsuits against us, our LBAs, permits and other industry regulatory processes and approvals may also be subject to legal challenges that may adversely impact our mining operations
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. Commitments and Contingencies (Continued)
and results. For example, the West Antelope II LBA, which we have nominated for lease with the Bureau of Land Management, is subject to pending legal challenges filed in 2010 against the Bureau of Land Management and the Secretary of the Interior by environmental organizations.
Tax Contingencies
Our income tax calculations are based on application of the respective U.S. federal or state tax law. Our tax filings, however, are subject to audit by the respective tax authorities. Accordingly, we recognize tax benefits when it is more likely than not a position will be upheld by the tax authorities. To the extent the final tax liabilities are different from the amounts originally accrued, the increases or decreases are recorded as income tax expense. We are not potentially liable for income tax contingencies related to periods prior to our IPO, as the income taxes recognized in our consolidated financial statements for such periods were reported in Rio Tinto America's consolidated income tax returns, and Rio Tinto has agreed to indemnify us for any claims related to such income taxes.
Several audits involving our taxes other than income taxes currently are in progress. We have provided our best estimate of taxes and related interest and penalties due for potential adjustments that may result from the resolution of such tax audits.
Concentrations of Risk and Major Customer
Approximately 83%, 84% and 69% of our revenues for the years ended December 31, 2010, 2009 and 2008, respectively, were under multi-year contracts which specify pricing terms. While the majority of the contracts are fixed-price contracts, certain contracts have escalation provisions for determining periodic price changes. No single customer accounted for 10% or more of revenues in 2010. One customer accounted for revenues of $140.4 million and $135.1 million for the years ended December 31, 2009 and 2008, respectively, representing more than 10% of consolidated revenues. We generally do not require collateral or other security on accounts receivable because our customers are comprised primarily of investment grade electric utilities. The credit risk is controlled through credit approvals and monitoring procedures.
Guarantees and Off-Balance Sheet Risk
In the normal course of business, we are party to guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit, performance or surety bonds and indemnities, which are not reflected on the consolidated balance sheet. In our past experience, virtually no claims have been made against these financial instruments. Management does not expect any material losses to result from these guarantees or off-balance-sheet instruments.
United States federal and state laws require we secure certain of our obligations to reclaim lands used for mining and to secure coal lease obligations. The primary method we have used to meet these reclamation obligations and to secure coal lease obligations is to provide a third-party surety bond, typically through an insurance company, or provide a letter of credit, typically through a bank. Specific bond and or letter of credit amounts may change over time, depending on the activity at the respective site and any specific requirements by federal or state laws. As of December 31, 2010, we had $10.5 million of standby of letters of credit and $525.0 million of performance bonds outstanding (including our proportional share of the Decker mine) to secure certain of our obligations to reclaim lands used for mining and to secure coal lease obligations.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
18. Related Party Transactions
Credit Arrangements and Guarantee Fees
While we were a subsidiary of Rio Tinto, Rio Tinto served as guarantor of our surety bonds and certain letters of credit securing our obligations were issued on our behalf under Rio Tinto's credit facilities. In connection with the IPO structuring transactions, we agreed to use our commercially reasonable efforts to obtain new surety bonds, letters of credit or other credit arrangements and to obtain the full release of Rio Tinto with respect to the existing arrangements. As of December 31, 2009, Rio Tinto remained the guarantor under these arrangements and we maintained $80.2 million in restricted cash as collateral for the benefit of Rio Tinto. As of December 31, 2010, we had obtained replacement surety bonds for all of the $445.5 million in bonds for which Rio Tinto had been the guarantor. Included in interest expense was $683,000 in fees Rio Tinto charged us in connection with transitional support of our credit arrangements for the year ended December 31, 2010, and $1.2 million of guarantee fees for the year ended December 31, 2009.
Transitional Support Services
Following our IPO, Rio Tinto affiliates provided certain transitional support services to us pursuant to a transition services agreement. Costs incurred under this agreement are included in selling, general and administrative expenses and totaled $464,000 for the period from November 20, 2009 to December 31, 2009.
We began leasing office space from Rio Tinto America during 2007. Rental expense for this lease was $245,000, $367,000 and $651,000 for the years ended December 31, 2010, 2009 and 2008, respectively.
Following the distribution of our interests in Colowyo and the uranium mining venture (see Note 4), we provided certain transitional management and administrative support services to the distributed entities on a cost reimbursement basis. Fees for these transitional support services are included as a reduction in cost of product sold and selling, general and administrative expenses, and totaled $1.4 million for the year ended December 31, 2009. These transitional services were terminated in March 2009.
Coal Sales
Included in revenues were $27.7 million, $21.4 million and $13.6 million for the years ended December 31, 2010, 2009 and 2008, respectively, for sales of coal to Venture Fuels Partnership, a 50% owned coal marketing company.
Other Commercial Transactions
From time to time, we enter into arms-length commercial arrangements in the ordinary course of business with Rio Tinto, including selling coal to Rio Tinto and engaging Rio Tinto for agency services in connection with our export coal sales. Since our November 2009 IPO and through the twelve months ended December 31, 2010, we have paid approximately $0.3 million for agency services and received $8.6 million for export coal sales agreements. For calendar years 2011 and 2012, we expect to pay approximately $0.7 million for agency services and receive approximately $17.4 million for export coal sales agreements based on currently proposed transactions.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
18. Related Party Transactions (Continued)
For additional related party transactions, see "Initial Public Offering, Related IPO Structuring Transactions, and Secondary Offering" and "Pre-IPO Expense Allocations" in Note 2 and Part III of this Form 10-K.
19. Segment Information
Our management reviews, manages and operates our business as a single operating segment-the production of low sulfur, steam coal from surface mines, located in the Western region of the U.S. within the Powder River Basin ("PRB"), which is sold to electric utilities and industrial customers.
The following table presents a summary of total revenues from external customers by geographic location for the years ended December 31 (in thousands):
We attribute revenue to individual countries based on the location of the customer. Our sales outside of the United States are made primarily to customers in Asia and Canada.
As of December 31, 2010 and 2009, all of our long-lived assets were located in the U.S. All of our revenues for the years ended December 31, 2010, 2009 and 2008 originated in the U.S.
20. Cloud Peak Energy Inc. (Parent Company Only) Financial Information
The following parent company only condensed financial information reflects the financial condition, results of operations and cash flows of Cloud Peak Energy Inc. The results of operations and cash flows are for the years ended December 31, 2010, 2009 and 2008.
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
20. Cloud Peak Energy Inc. (Parent Company Only) Financial Information (Continued)
Condensed Statements of Operations
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
20. Cloud Peak Energy Inc. (Parent Company Only) Financial Information (Continued)
Condensed Balance Sheets
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
20. Cloud Peak Energy Inc. (Parent Company Only) Financial Information (Continued)
Condensed Statements of Cash Flows
21. Summary Unaudited Quarterly Financial Information
A summary of the unaudited quarterly results of operations for the years ended December 31, 2010 and 2009 is presented below (in thousands except share amounts).
Our second, third and fourth quarter 2010 operating results included $4.3 million ($3.5 million after tax), $4.3 million ($3.5 million after tax), and $6.8 million ($4.4 million after tax) charges due to updates to estimates for non-income based taxes.
Our third quarter 2010 operating results included a $19.7 million charge to income from continuing operations and a $5.4 million charge to income tax expense related to our Tax Receivable
CLOUD PEAK ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
21. Summary Unaudited Quarterly Financial Information (Continued)
Agreement. See Note 17. This adjustment reduced third quarter income from continuing operations and net income by $25.1 million, and reduced related basic and diluted per share amounts by $0.77.
In the fourth quarter of 2010, we completed the Secondary Offering (see Note 2).
In the fourth quarter of 2009, we sold the Jacobs Ranch mine (see Note 4), completed our initial public offering and related IPO structuring transactions (see Note 2), entered into debt financing transactions, including the issuance of our Senior Notes and the execution of our Credit Facility (see Note 9) and granted share-based compensation awards to our employees and directors (see Note 15).
Our fourth quarter 2009 operating results included a $3.6 million favorable adjustment to amortization expense related to an acquired coal supply contract that expires in 2010. See Note 7. This adjustment increased fourth quarter income from continuing operations and net income by $2.5 million, and increased related diluted per share amounts by $0.01, with no impact on related basic per share amounts.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None
Item 9A.
Item 9A. Controls and Procedures.
Disclosure Controls and Procedures
An evaluation was performed by management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2010. Our Chief Executive Officer and Chief Financial Officer, have concluded that our disclosure controls and procedures, which are designed to provide reasonable assurance that information required to be disclosed in reports filed under the Securities and Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the specified time periods and accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure, were effective at a reasonable assurance level as of December 31, 2010.
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected.
Management's Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer, and effected by our Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with generally accepted accounting principles.
Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management conducted an evaluation of the effectiveness of our internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2010.
Our independent registered public accounting firm, PricewaterhouseCoopers LLP, has audited the effectiveness of our internal control over financial reporting as of December 31, 2010, as stated in their audit report included herein.
Remediation Steps to Address the Previously Disclosed Material Weaknesses
We previously reported material weaknesses in our internal controls over financial reporting related to maintaining a sufficient complement of personnel with an appropriate level of accounting, taxation and financial reporting knowledge, experience and training in the application of U.S. GAAP
commensurate with our financial reporting requirements on a stand-alone basis and the complexity of our operations and transactions. The previously reported material weaknesses also related to maintaining an adequate system of processes and internal controls sufficient to support our financial reporting requirements and produce timely and accurate U.S. GAAP consolidated financial statements consistent with being a stand-alone public company.
We have implemented changes and improvements in our internal control over financial reporting to remediate the control deficiencies that gave rise to the material weaknesses. These changes included:
•employing a new Vice President and Chief Accounting Officer; Vice President, Treasury; Vice President, Tax; Vice President, Investor Relations; Director, Internal Audit; and Senior Vice President and General Counsel, all of whom have experience in large U.S. publicly traded companies;
•making numerous policy and procedure changes as part of our on-going program to strengthen the organization structure, financial reporting procedures and system of internal control over financial reporting; and
•making other changes to improve the effectiveness of our internal control over financial reporting, including upgrading our financial reporting function and documenting and testing our key internal controls.
We completed the remedial procedures described above and have concluded that the steps taken were sufficient to eliminate the previously disclosed material weaknesses.
Changes in Internal Control Over Financial Reporting
As described above, there were changes in our internal control over financial reporting during the quarter ended December 31, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
We had a strong safety performance in 2010. According to MSHA data for our three owned and operated mines, we had one of the lowest 2010 all injury frequency rates (AIFR) among the ten largest U.S. coal producers of 0.58. For the three months ended December 31, 2010, the AIFR for our three owned and operated mines was 0.27 (calculated internally based on MSHA methodology). The AIFR is the number of reportable injuries suffered by employees per 200,000 hours worked.
Quarterly Reporting Pursuant to Wall Street Reform and Consumer Protection Act Section 1503
As provided by Section 1503 of the Wall Street Reform and Consumer Protection Act, Cloud Peak Energy provides the following safety-related information for our three operated mines:
(1)Total number of violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a coal mine safety or health hazard under section 104 of the Federal Mine Safety and Health Act of 1977 (30 U.S.C. 814) (the Act) for which we received a citation from MSHA.
(2)Total number of orders issued under section 104(b) of the Act (30 U.S.C. 814(b)).
(3)Total number of citations and orders for unwarrantable failure of Cloud Peak Energy to comply with mandatory health or safety standards under section 104(d) of the Act (30 U.S.C. 814(d)).
(4)Total number of flagrant violations under section 110(b)(2) of the Act (30 U.S.C. 820(b)(2)).
(5)Total number of imminent danger orders issued under section 107(a) of the Act (30 U.S.C. 817(a)).
(6)Total dollar value of proposed assessments from MSHA under the Act (30 U.S.C. 801 et seq.).
(7)Total number of mining-related fatalities.
(8)Any coal mines owned and operated by us that received written notice from MSHA of (A) a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal mine health or safety hazards under section 104(e) of such Act (30 U.S.C. 814(e)); or (B) the potential to have such a pattern.
(9)Any pending legal action before the Federal Mine Safety and Health Review Commission involving a coal mine owned and operated by us.
(10)Docket No. WEST 2010-1314-D in which a terminated employee claims that such termination constituted unlawful retaliation for alleged safety-related statements made to the company.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
The information required by Items 401, 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K is included under the caption Election of Class II Directors in our Proxy Statement to be distributed to our stockholders in connection with our 2011 annual meeting and in Part I of this report under the caption Executive Officers of the Company. Such information is incorporated herein by reference. The information required by Items 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K is included under the captions Section 16(a) Beneficial Ownership Reporting Compliance, Corporate Governance and Executive Compensation, respectively, in our Proxy Statement to be distributed to our stockholders in connection with our 2011 annual meeting under the caption Executive Compensation and is incorporated herein by reference.
Item 11.
Item 11. Executive Compensation.
The information required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K is included in our Proxy Statement to be distributed to our stockholders in connection with our 2011 annual meeting under the caption Executive Compensation and is incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by Item 403 of Regulation S-K is included under the caption Security Ownership of Management and Principal Stockholders in our Proxy Statement to be distributed to our stockholders in connection with our 2011 annual meeting and is incorporated herein by reference.
As required by Item 201(d) of Regulation S-K, the following table provides information regarding our equity compensation plans as of December 31, 2010:
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by Item 404 of Regulation S-K is included under the captions Certain Relationships and Related Transactions and Independence of Directors in our Proxy Statement and is incorporated herein by reference. The information required by Item 407(a) of Regulation S-K is included under the caption Executive Compensation in our Proxy Statement to be distributed to our stockholders in connection with our 2011 annual meeting and is incorporated herein by reference.
Item 14.
Item 14. Principal Accounting Fees and Services.
The information required by Item 9(e) of Schedule 14A is included under the caption Fees Paid to Independent Registered Public Accounting Firm in our Proxy Statement to be distributed to our stockholders in connection with our 2011 annual meeting and is incorporated herein by reference.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)The following documents are filed as part of this Report:
(1)
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2010 and 2009
Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008
Consolidated Statements of Equity for the Years Ended December 31, 2010, 2009 and 2008
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008
Notes to Consolidated Financial Statements
(2)
Reserved
(3)
Exhibit List
(b)Exhibits The following documents are filed as part of this annual report on Form 10-K. The Company will furnish a copy of any exhibit listed to requesting stockholders upon payment of the Company's reasonable expenses in furnishing those materials.
*Filed or furnished herewith
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Act, this registration statement has been signed by the following persons in the capacities and on the dates indicated:
EXHIBIT INDEX
The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.
*Filed or furnished herewith