Cloud Peak Energy Inc. Announces Results For Fourth Quarter And Full Year 2012

Cloud Peak Energy Inc. (NYSE:CLD), one of the largest U.S. coal producers and the only pure-play Powder River Basin (“PRB”) coal company, today announced results for the fourth quarter and full year 2012.

2012 Highlights and Recent Developments
  • Reduced All Injury Frequency Rate by 31% from 1.18 last year to 0.82 in 2012.
  • Adjusted EBITDA(1) of $338.8 million for the full year 2012 compared with $351.7 million for 2011; Adjusted EBITDA of $89.0 million in the fourth quarter 2012 compared with $92.9 million in the fourth quarter 2011.
  • 2012 net income of $173.7 million resulting in diluted EPS of $2.85 compared to $3.13 for 2011. Fourth quarter 2012 net income of $28.2 million and diluted EPS of $0.46 compared to $0.72 in the fourth quarter 2011.
  • Adjusted EPS(1) of $2.15 for 2012, and $0.54 for the fourth quarter, compared to $2.47 for 2011 and $0.70 for the fourth quarter 2011.
  • Cash and investments were $278.0 million and total available liquidity was $778 million as of December 31, 2012. We generated $247.4 million in cash from operations for the full year 2012. During the fourth quarter, we generated cash from operations of $45.4 million.
  • Annual shipments of 90.6 million tons from our three operated mines. Asian exports were approximately 0.9 million tons in the fourth quarter 2012 compared to 1.0 million tons in the fourth quarter 2011. For the full year, Asian exports were 4.4 million tons, down from 4.7 million tons in the full year 2011.
  • Proven and probable reserves of 1.3 billion tons at December 31, 2012.
  • Acquired Youngs Creek project with over 450 million tons of in-place coal, of which 287 million tons are now classified as non-reserve coal deposits, along with 38,800 acres of surface land in the Northern Powder River Basin (“NPRB”) to further Cloud Peak Energy’s potential for increased Asian exports.
  • Signed option and exploration agreements with the Crow Indian Tribe covering up to 1.4 billion tons of in-place coal near Cloud Peak Energy’s NPRB properties. Department of Interior approval of the agreements is pending.
  • Announced an agreement to sell our 50% interest in the Decker mine to Ambre Energy with the consideration including an option for up to 5 million tonnes of annual capacity through Ambre’s planned Millennium Bulk Terminal.
  • Today announced a throughput option agreement with SSA Marine that provides Cloud Peak Energy with an option for up to 16 million tonnes of capacity per year through the planned dry bulk cargo Gateway Pacific Terminal at Cherry Point in the State of Washington.

(1) Defined later.

“Given the challenging external environment in 2012, I am very pleased with the operational and financial performance of the company,” said Colin Marshall, President and Chief Executive Officer. “Our operations have done a great job of controlling costs in a year when shipments varied significantly from quarter to quarter. We continued to position ourselves for future export growth by completing a number of important transactions. In June, we purchased the Youngs Creek project, adjacent to our Spring Creek mine, with over 450 million tons of in-place coal, of which 287 million tons are now classified as non-reserve coal deposits, and over 38,800 acres of land. Last month we signed the exploration and option agreements with the Crow Tribe covering up to 1.4 billion tons of in-place coal also located close to our Spring Creek mine. We concluded an option agreement with SSA Marine for up to 16 million tonnes of annual port capacity at its proposed Gateway Pacific Terminal and expect to soon have an option for up to 5 million tonnes of annual capacity at Ambre Energy’s proposed Millennium Bulk Terminal as part of the pending sale of our 50% interest in the Decker mine. It has been a busy year for Cloud Peak Energy as we position ourselves for future growth.”

Health, Safety and Environment Record

During 2012, of our nearly 1,400 full-time mine site employees, 12 suffered minor reportable injuries resulting in a year-to-date MSHA All Injury Frequency Rate of 0.82, a decrease over the full year 2011 rate of 1.18. During the six MSHA inspector days in the fourth quarter of 2012, we were issued one substantial and significant (“S&S”) citation. “Our 2012 safety performance improved significantly over 2011 and thankfully the 12 injuries that did occur were relatively minor. We will continue to stay focused on safety throughout 2013,” said Marshall.

In 2012, Cloud Peak Energy, along with other members of the National Mining Association, announced their commitment to implement a new workplace safety and health program called CORESafety. This paradigm is a scalable safety and health management system specifically designed for U.S. mining operations and is consistent with existing Cloud Peak Energy approaches. CORESafety provides a comprehensive pathway to achieve its members’ goals of eliminating fatalities and reducing the rate of mining injuries by 50% within five years.

In 2012, Cloud Peak Energy successfully retained our ISO 14001 environmental certification. ISO 14001 is an internationally recognized certification that defines the requirements for establishing, implementing and operating an effective environmental management system. We believe Cloud Peak Energy continues to be the only PRB coal company to maintain this certification.

Consolidated Business Results

The following table summarizes certain consolidated results (in millions, except per share amounts):
  Q4   Q4   Full Year   Full Year
2012 2011 2012   2011
Total revenue

$ 374.8   $ 402.5 $ 1,516.8   $ 1,553.7
Net income 28.2 43.8 173.7 189.8
Adjusted EBITDA(1) 89.0 92.9 338.8 351.7
Adjusted EPS(1)

$ 0.54 $ 0.70 $ 2.15 $ 2.47
Asian export tons – Logistics and Related Activities 0.9 1.0 4.4 4.7
Total tons sold 24.3 26.0 93.0 98.7

(1) Non-GAAP financial measure; please see definition and reconciliation below in this release and the attached tables.

Total revenue declined 2.4% for the full year 2012 due to 5.7 million fewer tons sold, partly offset by a 2% rise in realized prices. Correspondingly, Adjusted EBITDA for the full year 2012 declined 4% to $338.8 million, down from $351.7 million in 2011.

Total revenue declined 6.9% in the fourth quarter 2012 due to 1.7 million fewer tons sold. Correspondingly, Adjusted EBITDA for the fourth quarter 2012 declined 4% to $89.0 million, down from $92.9 million in the fourth quarter 2011.

Operating Segments

Historically, we have reported one segment. As of December 31, 2012, we are now presenting three segments: Owned and Operated Mines; Logistics and Related Activities; and Corporate and Other.

Owned and Operated Mines

Our Owned and Operated Mines segment comprises the results of mine site sales from our three owned and operated mines primarily to our domestic utility customers and also to our Logistics and Related Activities segment.
(in millions, except per ton amounts)   Q4   Q4   Full Year   Full Year
2012 2011   2012   2011
Tons sold 23.6 25.2 90.6 95.6
Realized price per ton sold $ 13.07 $ 13.06 $ 13.19 $ 12.92
Average cost of product sold per ton $ 9.38 $ 9.15 $ 9.57 $ 9.12
Adjusted EBITDA (1) $ 75.4 $ 88.2 $ 283.3 $ 318.8

(1) Non-GAAP financial measure; please see definition and reconciliation below in this release and the attached tables.

Mine site sales volumes in the fourth quarter 2012 were down 6% over the fourth quarter 2011 due to weaker demand for coal nationwide. Mine site sales volumes for the full year 2012 were down 5% over 2011. The lower demand for our coal was primarily a result of the warm 2011/2012 winter. This resulted in lower electricity demand and lower natural gas prices that allowed utilities to opportunistically switch generation to gas. As a result, during the first half of the year, utilities stockpiled a portion of their contracted coal. While PRB coal burn has recovered some ground as natural gas prices have risen, stockpiles are still at elevated levels.

In response to weak market conditions and reduced production, our operations focused successfully on controlling variable costs. Condition monitoring and planned maintenance programs continue to allow equipment lives to be extended and reduce maintenance costs without compromising equipment integrity. Costs were also managed by reducing the use of outside contractors, matching hiring to production and completing more maintenance and capital projects without using contractors.

The average price realized for a ton of coal in 2012 was up 2% to $13.19 from $12.92 in 2011. Our average cost per ton was $9.57 in 2012, up from $9.12 in 2011 driven primarily by lower tonnage produced. The 2012 full year operating margin was $3.62 per ton, down slightly from $3.80 per ton for full year 2011.

Logistics and Related Activities

Our Logistics and Related Activities segment comprises the results of our logistics and transportation services to our domestic and international customers.
(in millions)   Q4   Q4   Full Year   Full Year
2012 2011 2012 2011
Tons delivered 1.3 1.3 5.8 5.9
Revenue $ 65.1 $ 72.3 $ 338.8 $ 327.4
Cost of product sold (delivered tons) $ 57.5 $ 66.2 $ 280.2 $ 294.2
Adjusted EBITDA (1) $ 15.4 $ 2.6 $ 57.1 $ 24.7

(1) Non-GAAP financial measure; please see definition and reconciliation below in this release and the attached tables.

Overall, shipments where we delivered coal to our customers were marginally lower in 2012. This comprised a 0.2 million ton increase in our domestic deliveries, combined with a 0.3 million ton reduction in our international deliveries. As international coal prices fell our export deliveries were reduced as we curtailed shipments through the Ridley terminal due to the greater rail costs for shipments through that terminal and focused on deliveries through the Westshore terminal. As a result of fewer tons being transported by us through the Ridley terminal, which is over 2,600 miles from our mines and can require us to utilize up to three different rail carriers, we were able to reduce the costs of deliveries in 2012 compared to 2011.

Adjusted EBITDA increased $32.4 million over 2011, due to higher international realized prices at the time we contracted our deliveries; lower costs as we curtailed deliveries through the Ridley Terminal; and realized derivative gains of $11.2 million. Our Asian delivered sales are priced broadly in line with a number of international coal price indices adjusted for energy content and other quality and delivery criteria. These indices include the Newcastle benchmark price which is an established index for high Btu Australian thermal coal available to be loaded on a vessel at a coal terminal near Newcastle, north of Sydney, Australia. Based on comparative quality and transport costs, our delivered international sales are generally priced in a range around 60% to 70% of the forward Newcastle price. We also use derivative financial instruments to help secure forward prices on a portion of our international coal deliveries and realized gains of $11.2 million in 2012. There were no realized gains in 2011. Domestic deliveries of 1.4 million tons were made to a number of utility and industrial customers in 2012, up from 1.2 million tons in 2011.

Corporate and Other

Our Corporate and Other segment comprises the results of our broker activities, our share of the Decker mine and unallocated corporate costs.

Adjusted EBITDA for Corporate and Other for full year 2012 was less than $0.1 million, compared to $8.1 million in 2011. The decrease was due to reduced earnings at the Decker mine and reduced broker activities in 2012.

Balance Sheet and Cash Flow

Cash flow from operations totaled $45.4 million for the fourth quarter of 2012 compared to $84.3 million for the fourth quarter 2011. Capital expenditures (excluding capitalized interest) were $17.1 million for the fourth quarter 2012 compared to $26.7 million for fourth quarter 2011. We also invested $7.4 million in port development projects. Cash flow from operations was $247.4 million for 2012 down from $296.8 million for full year 2011. Capital expenditures were $103.7 million for the full year 2012 (including $50 million of capitalized interest) compared to $142.7 million for the full year 2011 (including $34 million of capitalized interest). In addition, coal lease payments of $129.2 million were made in 2012, and we used $300 million of available cash to fund the Youngs Creek acquisition.

Unrestricted cash and investments as of December 31, 2012 were $278.0 million, down from $479.5 million at December 31, 2011. “Our strong operational performance continues to provide the cash flow to make the investments that will serve us well in the future,” said Michael Barrett, Chief Financial Officer. “We are fortunate to have a strong balance sheet and total available liquidity of $778 million as of December 31, 2012.”

Subsequent to year end, we put in place an accounts receivable securitization program with revolving capacity up to $75 million, further increasing our available liquidity.

West Coast Export Terminals Update

Cloud Peak Energy announced today that we have reached an agreement with SSA Marine that provides us an option for up to 16 million tonnes of capacity per year through the planned dry bulk cargo Gateway Pacific Terminal at Cherry Point in the State of Washington. This terminal will accommodate cape size vessels. The Gateway Pacific Terminal is intended to be capable of annually exporting up to 54 million tonnes of commodities, including 48 million tonnes of coal. Our potential share of capacity will depend upon the ultimate capacity of the terminal. Subsequent to receiving the required permits, SSA Marine anticipates approximately two years for construction. Commercial operation is currently estimated to commence in 2018.

As part of the pending sale of our 50% interest in the Decker mine, Ambre Energy will grant Cloud Peak Energy options for up to 5 million tonnes per year of throughput capacity at the proposed Millennium Bulk Terminals coal export facility in the State of Washington. This terminal is expected to be developed in two stages. The first stage is planned to have capacity of 25 million tonnes per year with the second stage taking annual capacity to 44 million tonnes. Cloud Peak Energy’s options would cover up to 2 million tonnes per year of Ambre’s share of the first phase and 3 million tonnes per year of its share of the second phase.

On December 7, 2012, a vessel berthing at the Westshore terminal collided with the trestle leading to their larger berth leaving it inoperable. As a result, the terminal capacity was reduced to below 50% of the normal throughput. On February 8, 2013, Westshore announced that repairs to the damaged trestle at Berth 1 were completed to permit resumption of normal operations at Berth 1, and we expect to recommence shipments on this berth shortly.

Decker Coal Mine Divesture

Cloud Peak Energy and Ambre Energy announced that their companies entered into agreements for Ambre Energy to purchase Cloud Peak Energy’s 50% interest in the Decker mine in Montana and assume all reclamation liabilities. The agreements will also provide for the joint resolution and dismissal of the pending Decker litigation. The closing of the transaction is currently anticipated to occur during the first half of 2013 and is subject to the satisfaction of various terms and conditions, including Ambre Energy’s full replacement of Cloud Peak Energy’s $70.7 million in outstanding reclamation and lease bonds for the Decker mine.

In addition to our options at Millennium Bulk Terminals described above, the consideration for the Decker interest also includes a cash component of A$57 million, if paid by Ambre Energy by March 31, 2013. Alternatively, Ambre will issue a promissory note to Cloud Peak Energy for A$64 million payable at a later date. The companies also entered into other agreements intended to facilitate the respective mining and related activities at the Decker mine and at Cloud Peak Energy’s adjacent Spring Creek mine and Youngs Creek development project. The sale also includes the transfer of certain land and grants of rail easements that will improve Cloud Peak Energy’s potential rail access to the Youngs Creek project.

Crow Project

In January 2013, we executed an Option Agreement and a corresponding Exploration Agreement with the Crow Tribe of Indians. These agreements remain subject to approval by the Department of the Interior. This coal project is located on the Crow Indian Reservation in southeast Montana, near our Spring Creek mine and Youngs Creek project in the Northern PRB region. In exchange for an option to lease up to 1.4 billion tons of in-place coal, we paid the Crow Tribe $2.25 million upon execution of the Option Agreement, and will pay $1.5 million upon approval of the Option Agreement by the Department of the Interior. In addition, we will pay annual option payments throughout the term of the Option Agreement, which, during the initial option period could total up to $10 million. The Option and Exploration Agreements provide for exploration rights and exclusive options to lease three separate coal deposits on the Crow Indian Reservation over an initial five-year term, with two extension periods through 2035 if certain conditions are met.


For 2013, our Owned and Operated Mines segment is expected to experience relatively flat revenue compared to 2012 as realized prices are not expected to increase. Costs at the mines are expected to increase as the mines naturally progress and the increased strip ratio requires additional labor, consumables, and equipment. The combination of these factors will reduce our 2013 earnings.

Currently, we have contracted 89 million tons to be delivered in 2013, of which 81 million tons are under fixed-price contracts with a weighted-average mine site price of $13.40 per ton. Assuming constant prices of $11.00 per ton for 8800 Btu quality coal and $9.50 per ton for 8400 Btu quality coal on our indexed tons, the expected total realized price for 2013 would be approximately $13.14 per ton. For 2014, we have currently contracted to sell 57 million tons from our three company-operated mines. Of this committed 2014 production, 44 million tons are under fixed-price contracts with a weighted-average price of $14.49 per ton.

Despite the recent delays due to the berth outage at Westshore, we continue to expect to deliver approximately 4.5 million tons to international customers from our Logistics and Related Activities segment in 2013. Due to low current prices, we have so far only priced approximately 1.7 million tons and expect to price the remaining deliveries in the coming months. Current Newcastle spot prices are approximately $90 to $95 per tonne, whereas the Newcastle index averaged approximately $116 per tonne at the time we priced our export deliveries for 2012.

In recent months, Newcastle prices appear to have reached a floor where existing production is being curtailed and potential new mining projects cancelled. This is particularly true of Australian production, which has recently suffered from significant cost pressure and additional taxation. During 2012, Chinese thermal and metallurgical coal imports continued to grow rapidly to 289 million tonnes, which included record December shipments of over 35 million tonnes, even with slower economic growth in China. We are hopeful that reduced international production and growing demand will support higher international delivered prices later in 2013. We have held off pricing export deliveries for the second half of 2013 to allow us to benefit if prices do rise in the next few months.

“We would have liked to have come into 2013 with a few more tons committed for future years, but the prices were such that additional contracting for 2014 and 2015 would not have been prudent in our view. We are optimistic that with normal winter weather that domestic utility stockpiles will come back into balance by the middle of the year, which should allow prices for PRB coal to rise. The very mild 2011/12 winter and low natural gas prices accelerated the trend we have been seeing of utilities reducing their forward contracting in the face of regulatory uncertainty and substituting low price natural gas when available. We believe that more utilities will be buying coal in-year, and if prices are economic, we will participate in that contracting. We will be responsive to our customers and the market and plan our costs and investments accordingly,” said Marshall. “While 2013 is likely to be a challenging year for U.S. coal producers, I believe market conditions will improve through the year and that Cloud Peak Energy is well placed to prosper as they do, particularly in 2014.”

2013 Guidance – Financial and Operational Estimates

The following table provides our current outlook and assumptions for selected 2013 consolidated financial and operational metrics:
Item   Estimate or Estimated Range
Coal shipments for our three operated mines (1)   87 - 93 million tons
Committed sales with fixed prices   Approximately 81 million tons
Anticipated realized price of produced coal with fixed prices   Approximately $13.40 per ton
Adjusted EBITDA (2)   $230 - $300 million
Net interest expense   Approximately $40 million
Depreciation, depletion and accretion   $110 - $120 million
Effective income tax rate (3)   Approximately 36%
Capital expenditures (4)   $80 - $110 million
Committed federal coal lease payments   $79 million
(1)       Inclusive of intersegment sales.
(2) Non-GAAP financial measure; please see definition below in this release.
(3) Excluding impact of the Tax Receivable Agreement.
(4) Excluding federal coal lease payments.

Conference Call Details

A conference call with management is scheduled at 5:00 p.m. ET on February 13, 2013 to review the results and current business conditions. The call will be webcast live over the Internet from our website at under “Investor Relations.” Participants should follow the instructions provided on the website for downloading and installing the audio applications necessary to join the webcast. Interested individuals also can access the live conference call via telephone at 866.362.4820 (domestic) or 617.597.5345 (international) and entering pass code 42239196.

Following the live webcast, a replay will be available at the same URL on our website for seven days. A telephonic replay will also be available approximately two hours after the call and can be accessed by dialing 888.286.8010 (domestic) or 617.801.6888 (international) and entering pass code 11527401. The telephonic replay will be available for seven days.

About Cloud Peak Energy ®

Cloud Peak Energy Inc. (NYSE:CLD) is headquartered in Wyoming and is one of the largest U.S. coal producers and the only pure-play PRB coal company. As one of the safest coal producers in the nation, Cloud Peak Energy specializes in the production of low sulfur, subbituminous coal. The company owns and operates three surface coal mines in the PRB, the lowest cost major coal producing region in the nation. The Antelope and Cordero Rojo mines are located in Wyoming and the Spring Creek mine is located near Decker, Montana. Cloud Peak Energy also owns rights to substantial undeveloped coal and complementary surface assets in the Northern PRB, further building the company’s long-term position to serve Asian export and domestic customers. With approximately 1,700 employees, the company is widely recognized for its exemplary performance in its safety and environmental programs. Cloud Peak Energy is a sustainable fuel supplier for approximately 4% of the nation’s electricity.

Cautionary Note Regarding Forward-Looking Statements

This release and our related presentation contain “forward-looking statements” within the meaning of the safe harbor provisions of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are not statements of historical facts and often contain words such as “may,” “will,” “expect,” “believe,” “anticipate,” “plan,” “estimate,” “seek,” “could,” “should,” “intend,” “potential,” or words of similar meaning. Forward-looking statements are based on management’s current expectations, beliefs, assumptions and estimates regarding our company, industry, economic conditions, government regulations and energy policies and other factors. Forward-looking statements may include, for example, (1) our outlook for 2013 and future periods for our company, the PRB and the industry in general, and our operational, financial and export guidance, including any development of future terminal capacity or increased access to existing or future capacity; (2) anticipated economic conditions and demand by domestic and Asian utilities, including the anticipated impact on demand driven by regulatory developments and uncertainties; (3) the impact of competition from natural gas and other alternative sources of energy used to generate electricity; (4) coal stockpile levels and the impacts on future demand; (5) our plans to replace and/or grow our coal tons; (6) business development and growth initiatives; (7) operational plans for our mines; (8) our cost management efforts; (9) industry estimates of the EIA and other third party sources; (10) estimated Tax Receivable Agreement liabilities; (11) anticipated completion of the sale of our 50% interest in the Decker mine to Ambre Energy; (12) our estimates of the quality and quantity of economic coal associated with our development projects, the potential development of our Youngs Creek and other NPRB assets, and our potential exercise of options for Crow Tribal coal; and (13) other statements regarding our plans, strategies, prospects and expectations concerning our business, operating results, financial condition and other matters that do not relate strictly to historical facts. These statements are subject to significant risks, uncertainties, and assumptions that are difficult to predict and could cause actual results to differ materially and adversely from those expressed or implied in the forward-looking statements. Factors that could adversely affect our future results include, for example, (a) future economic and weather conditions; (b) coal-fired power plant capacity and utilization, demand for our coal by the domestic electric generation industry, Asian export demand and terminal capacity and the prices we receive for our coal and our logistics services; (c) reductions or deferrals of purchases by major customers and our ability to renew sales contracts; (d) competition from other coal producers, natural gas producers and other sources of energy, domestically and internationally, (e) environmental, health, safety, endangered species or other legislation, regulations, treaties, court decisions or government actions, or related third-party legal challenges or changes in interpretations, including new requirements or uncertainties affecting the use, demand or price for coal or imposing additional costs, liabilities or restrictions on our mining operations or the utility industry; (f) public perceptions, third-party legal challenges or governmental actions and energy policies relating to concerns about climate change, air quality or other environmental considerations, including emissions restrictions and governmental subsidies or mandates that make wind, solar or other alternative fuel sources more cost-effective and competitive with coal; (g) operational, geological, equipment, permit, labor, weather-related and other risks inherent in surface coal mining; (h) our ability to efficiently and safely conduct our mining operations, (i) transportation and export terminal availability, performance and costs; (j) availability, timing of delivery and costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires; (k) our ability to acquire future coal tons through the federal LBA process and necessary surface rights and permits in a timely and cost-effective manner and the impact of third-party legal challenges, (l) access to capital and credit markets and availability and costs of credit, surety bonds, letters of credit, and insurance; (m) litigation and other contingent liabilities; (n) the timing and ability of Ambre Energy to replace our outstanding reclamation and lease bonds for the Decker mine and pay the cash consideration for its pending purchase of Decker, (o) receipt of required DOI approval for the Crow Tribe transaction, (p) proposed Pacific Northwest export terminals are not developed in a timely manner or at all, or are developed at a smaller capacity than planned, or we are unable to finalize and enter into definitive throughput agreements for potential future capacity at proposed terminals, including the Gateway Pacific Terminal and the Millennium Bulk Terminal, (q) future development and operating costs for our development projects significantly exceed our expectations, and (r) other risk factors described from time to time in the reports and registration statements we file with the Securities and Exchange Commission (“SEC”), including those in Item 1A - Risk Factors in our most recent Form 10-K and any updates thereto in our Forms 10-Q and current reports on Forms 8-K. There may be other risks and uncertainties that are not currently known to us or that we currently believe are not material. We make forward-looking statements based on currently available information, and we assume no obligation to, and expressly disclaim any obligation to, update or revise publicly any forward-looking statements made in this release or our related presentation, whether as a result of new information, future events or otherwise, except as required by law.

Non-GAAP Financial Measures

This release and our related presentation include the non-GAAP financial measures of (1) Adjusted EBITDA (on a consolidated basis and for our reporting segments) and (2) Adjusted Earnings Per Share (“Adjusted EPS”). Adjusted EBITDA and Adjusted EPS are intended to provide additional information only and do not have any standard meaning prescribed by generally accepted accounting principles in the U.S. (“GAAP”). A quantitative reconciliation of historical net income to Adjusted EBITDA and EPS (as defined below) to Adjusted EPS is found in the tables accompanying this release.

EBITDA represents net income, or income from continuing operations, as applicable, before (1) interest income (expense) net, (2) income tax provision, (3) depreciation and depletion, (4) amortization, and (5) accretion. Adjusted EBITDA represents EBITDA as further adjusted to exclude specifically identified items that management believes do not directly reflect our core operations. The specifically identified items are the income statement impacts, as applicable, of: (1) the updates to the tax agreement liability, including tax impacts of our 2009 initial public offering and 2010 secondary offering, (2) adjustments for derivative financial instruments including mark-to-market amounts and cash settlements realized, and (3) our significant broker contract that expired in the first quarter of 2010. Because of the inherent uncertainty related to the items identified above, management does not believe it is able to provide a meaningful forecast of the comparable GAAP measures or a reconciliation to any forecasted GAAP measures.

Adjusted EPS represents diluted earnings (loss) per common share attributable to controlling interest, or diluted earnings (loss) per common share attributable to controlling interest from continuing operations, as applicable (“EPS”), adjusted to exclude the estimated per share impact of the same specifically identified items used to calculate Adjusted EBITDA and described above, adjusted at the statutory rate of 36%.

Adjusted EBITDA is an additional tool intended to assist our management in comparing our performance on a consistent basis for purposes of business decision-making by removing the impact of certain items that management believes do not directly reflect our core operations. Adjusted EBITDA is a metric intended to assist management in evaluating operating performance, comparing performance across periods, planning and forecasting future business operations and helping determine levels of operating and capital investments. Period-to-period comparisons of Adjusted EBITDA are intended to help our management identify and assess additional trends potentially impacting our company that may not be shown solely by period-to-period comparisons of net income or income from continuing operations. Our chief operating decision maker uses Adjusted EBITDA as a measure of segment performance. Consolidated Adjusted EBITDA is also used as part of our incentive compensation program for our executive officers and others.

We believe Adjusted EBITDA and Adjusted EPS are also useful to investors, analysts and other external users of our consolidated financial statements in evaluating our operating performance from period to period and comparing our performance to similar operating results of other relevant companies. Adjusted EBITDA allows investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and depletion, amortization and accretion and other specifically identified items that are not considered to directly reflect our core operations. Similarly, we believe our use of Adjusted EPS provides an appropriate measure to use in assessing our performance across periods given that this measure provides an adjustment for certain specifically identified significant items that are not considered to directly reflect our core operations, the magnitude of which may vary drastically from period to period and, thereby, have a disproportionate effect on the earnings per share reported for a given period.

Our management recognizes that using Adjusted EBITDA and Adjusted EPS as performance measures has inherent limitations as compared to net income, income from continuing operations, EPS or other GAAP financial measures, as these non-GAAP measures exclude certain items, including items that are recurring in nature, which may be meaningful to investors. Adjusted EBITDA and Adjusted EPS should not be considered in isolation and do not purport to be alternatives to net income, income from continuing operations, EPS or other GAAP financial measures as a measure of our operating performance. Because not all companies use identical calculations, our presentations of Adjusted EBITDA and Adjusted EPS may not be comparable to other similarly titled measures of other companies. Moreover, our presentation of Adjusted EBITDA is different than EBITDA as defined in our debt financing agreements.


Three Months Ended Year Ended
December 31,   December 31,
2012   2011 2012   2011
Revenues $ 374,825   $ 402,487   $ 1,516,772   $ 1,553,661  
Costs and expenses
Cost of product sold (exclusive of depreciation, depletion,
amortization and accretion, shown separately) 281,486 295,566 1,132,399 1,151,117
Depreciation and depletion 24,239 28,590 94,575 87,127
Accretion 3,862 3,049 13,189 12,469
Derivative finance instruments (3,293 ) (2,275 ) (22,754 ) (2,275 )
Selling, general and administrative expenses 13,402 13,438 54,548 51,061
Other operating costs   646     137     2,949     1,419  
Total costs and expenses   320,343     338,505     1,274,906     1,300,918  
Operating income   54,482     63,982     241,866     252,743  
Other income (expense)
Interest income 139 133 1,086 592
Interest expense (10,871 ) (6,346 ) (36,327 ) (33,866 )
Tax agreement benefit (expense) 29,000 (19,854 )
Other, net   (460 )   (135 )   (847 )   (170 )
Total other expense   (11,192 )   (6,348 )   (7,088 )   (53,298 )
Income before income tax provision and earnings from
unconsolidated affiliates 43,290 57,634 234,778 199,445
Income tax expense (15,104 ) (13,474 ) (62,614 ) (11,449 )
Earnings from unconsolidated affiliates, net of tax   (23 )   (341 )   1,556     1,801  
Net income   28,163     43,819     173,720     189,797  
Other comprehensive income
Retiree medical plan amortization of prior service costs 394 326 1,575 1,305
Retiree medical plan adjustment (4,664 ) (5,602 ) (4,665 ) (5,602 )
Decker pension adjustments 113 (1,885 ) 204 (1,885 )
Income tax on retiree medical plan and pension
adjustments   1,496     2,578     1,039     2,226  
Other comprehensive income   (2,661 )   (4,583 )   (1,847 )   (3,956 )
Total comprehensive income $ 25,502   $ 39,236   $ 171,873   $ 185,841  
Earnings per common share attributable to controlling interest:
Basic $ 0.47 $ 0.73 $ 2.89 $ 3.16
Diluted $ 0.46   $ 0.72   $ 2.85   $ 3.13  
Weighted-average shares outstanding - basic   60,382     60,007     60,093     60,004  
Weighted-average shares outstanding - diluted   61,260     60,741     60,927     60,637  

December 31,
ASSETS 2012   2011
Current assets
Cash and cash equivalents $ 197,691 $ 404,240
Investments in marketable securities 80,341 75,228
Restricted cash 71,245
Accounts receivable 76,117 95,247
Due from related parties 1,561 471
Inventories, net 81,675 71,648
Deferred income taxes 28,112 37,528
Derivative financial instruments 13,785 2,275
Other assets   16,513     13,019  
Total current assets 495,795 770,901
Noncurrent assets
Property, plant and equipment, net 1,678,294 1,350,135
Goodwill 35,634 35,634
Deferred income taxes 101,075 132,828
Other assets   40,525     29,821  
Total assets $ 2,351,323   $ 2,319,319  
Current liabilities
Accounts payable $ 49,589 $ 71,427
Royalties and production taxes 129,351 136,072
Accrued expenses 50,364 65,928
Current portion of tax agreement liability 19,485 19,113
Current portion of federal coal lease obligations 63,191 102,198
Other liabilities   2,770     4,971  
Total current liabilities 314,750 399,709
Noncurrent liabilities
Tax agreement liability, net of current portion 97,053 151,523
Senior notes 596,506 596,077
Federal coal lease obligations, net of current portion 122,928 186,119
Asset retirement obligations, net of current portion 238,991 192,707
Other liabilities   50,073     42,795  
Total liabilities   1,420,301     1,568,930  
Common stock ($0.01 par value; 200,000 shares authorized; 61,114 and 60,923 shares
issued and 60,839 and 60,923 outstanding at December 31, 2012 and 2011, respectively) 608 609

Treasury stock 276 shares and 0 shares at December 31, 2012 and 2011, respectively
(5,390 )
Additional paid-in capital 550,452 536,301
Retained earnings 405,813 232,093
Accumulated other comprehensive loss   (20,461 )   (18,614 )
Total equity   931,022     750,389  
Total liabilities and equity $ 2,351,323   $ 2,319,319  

Year Ended December 31,
Cash flows from operating activities 2012   2011   2010
Net income $ 173,720 $ 189,797 $ 117,197
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization 94,575 87,127 103,220
Accretion 13,189 12,469 12,499
Earnings from unconsolidated affiliates (1,556 ) (1,801 ) (3,189 )
Distributions of income from unconsolidated affiliates 1,023 5,250 35
Deferred income taxes 42,210 (11,224 ) 28,503
Tax agreement (benefit) expense (29,000 ) 19,854 19,669
Stock compensation expense 11,796 8,796 7,234
Mark-to-market gains (22,754 ) (2,275 )
Other 11,795 11,506 5,377
Changes in operating assets and liabilities:
Accounts receivable 18,632 (30,074 ) 17,636
Inventories, net (9,077 ) (6,452 ) (638 )
Due to or from related parties (1,090 ) (37 ) 7,906
Other assets (4,486 ) 4,436 (10,090 )
Accounts payable and accrued expenses (32,137 ) 26,327 27,040
Tax agreement liability (25,097 ) (9,409 ) (1,685 )
Asset retirement obligations (5,632 ) (7,506 ) (5,938 )
Settlement of derivatives   11,244          
Net cash provided by operating activities   247,355     296,784     324,776  
Investing activities
Acquisitions of Youngs Creek and CX Ranch coal and land assets (300,377 )
Purchases of property, plant and equipment (53,550 ) (108,733 ) (65,041 )
Cash paid for capitalized interest (50,119 ) (33,989 ) (26,598 )
Investments in marketable securities (67,576 ) (75,228 )
Maturity and redemption of investments 62,463
Investment in development projects (7,389 )
Initial payment on federal coal leases (69,407 )
Return of restricted cash 71,244 110,972 116,533
Partnership escrow deposit (4,470 )
Deposit of restricted cash (218,425 )
Other   1,909     713     1,511  
Net cash used in investing activities   (347,865 )   (175,672 )   (192,020 )
Financing activities
Principal payments on federal coal leases (102,198 ) (54,630 ) (50,768 )
Proceeds from issuance of common stock 65
Distributions to former parent (10,203 )
Other   (3,906 )   (2,343 )    
Net cash used in financing activities   (106,039 )   (56,973 )   (60,971 )
Net increase (decrease) in cash and cash equivalents (206,549 ) 64,139 71,785
Cash and cash equivalents at beginning of period   404,240     340,101     268,316  
Cash and cash equivalents at end of period $ 197,691   $ 404,240   $ 340,101  
Supplemental cash flow disclosures:
Interest paid $ 84,201 $ 62,792 $ 69,317
Income taxes paid, net $ 27,017 $ 6,161 $ 9,120
Supplemental noncash investing and financing activities:
Obligations to acquire federal coal leases and other mineral rights $ $ 224,658 $
Noncash interest capitalized $ 7,845 $ 16,092 $ 6,896
Capital expenditures included in accounts payable $ 4,579 $ 10,893 $ 37,541


Adjusted EBITDA
Three Months Ended Year Ended
December 31, December 31,
2012   2011 2012   2011
Net income $ 28.2 $ 43.8 $ 173.7 $ 189.8
Interest income (0.1 ) (0.1 ) (1.1 ) (0.6 )
Interest expense 10.9 6.3 36.3 33.9
Income tax expense 15.1 13.5 62.6 11.4
Depreciation and depletion 24.2 28.6 94.6 87.1
Accretion   3.9     3.0     13.2     12.5  
EBITDA   82.1     95.1     379.3     334.1  
Tax agreement expense(1) (29.0 ) 19.9
Derivative Financial instruments(2)   6.9     (2.3 )   (11.5 )   (2.3 )
Adjusted EBITDA $ 89.0   $ 92.9   $ 338.8   $ 351.7  
(1)   Changes to related deferred taxes are included in income tax expense.
(2) Mark-to-market and realized gains on derivative financial instruments consisted of the following (in millions):
      Three Months Ended   Year Ended
December 31, December 31,
2012   2011 2012   2011
Mark-to-market (gains) losses $ (3.3 ) $ (2.3 ) $ (22.8 ) $ (2.3 )
Realized gains (3)   10.2         11.2      
Net derivative financial instrument activity $ 6.9   $ (2.3 ) $ (11.5 ) $ (2.3 )

(3) Derivative cash settlement gains and losses reflected within operating cash flows.

Adjusted EPS
Three Months Ended Year Ended
December 31, December 31,
2012   2011 2012   2011
Diluted earnings per common share
attributable to controlling interest $ 0.46 $ 0.72   $ 2.85   $ 3.13  
Tax agreement expense including tax impacts of IPO and
Secondary Offering (0.58 ) (0.63 )
Derivative financial instrument   0.08   (0.02 )   (0.12 ) (0.02 )
Adjusted EPS $ 0.54 $ 0.70   $ 2.15   $ 2.47  
Weighted-average shares outstanding 61.3 60.7 60.9 60.6

Adjusted EBITDA by Segment
Three Months Ended Year Ended
December 31, December 31,
Owned and Operated Mines 2012   2011 2012   2011
Adjusted EBITDA $ 75.4 $ 88.2 $ 283.3 $ 318.8
Depreciation and depletion (23.4 ) (24.3 ) (89.2 ) (80.4 )
Accretion (2.8 ) (1.9 ) (9.5 ) (8.0 )
Derivative financial instruments (0.2 ) 0.1
Other   0.5     0.1     0.9     0.3  
Operating income   49.6     62.1     185.6     230.6  
Logistics and Related Activities
Adjusted EBITDA 15.4 2.6 57.1 24.7
Derivative financial instruments   (6.7 )   2.3     11.4     2.3  
Operating income   8.6     4.9     68.4     27.0  
Corporate and Other
Adjusted EBITDA (1.4 ) 1.7 8.1
Depreciation and depletion (0.9 ) (4.2 ) (5.3 ) (6.7 )
Accretion (1.1 ) (1.2 ) (3.7 ) (4.5 )
Earnings from unconsolidated affiliates, net of tax       0.3     (1.6 )   (1.8 )
Operating income   (3.3 )   (3.3 )   (10.5 )   (5.0 )
Adjusted EBITDA   (0.4 )   0.3     (1.6 )   0.1  
Operating income   (0.4 )   0.3     (1.6 )   0.1  
Consolidated operating income 54.5 64.0 241.9 252.7
Interest income 0.1 0.1 1.1 0.6
Interest expense (10.9 ) (6.3 ) (36.3 ) (33.9 )
Tax agreement expense 29.0 (19.9 )
Other, net (0.5 ) (0.1 ) (0.8 ) (0.2 )
Income tax expense (15.1 ) (13.5 ) (62.6 ) (11.4 )
Earnings from unconsolidated affiliates, net of tax       (0.3 )   1.6     1.8  
Net income $ 28.2   $ 43.8   $ 173.7   $ 189.8  

Due to the tabular presentation of rounded amounts, totals may reflect insignificant rounding differences.
Tons Sold                
(in thousands) Q4 Q3 Q2 Q1 Q4 Q3 Year Year
2012 2012 2012 2012 2011 2011 2012 2011
Antelope 9,029 9,111 7,424 8,752 9,948 8,901 34,316 37,075
Cordero Rojo 9,970 10,201 9,027 10,007 10,070 9,968 39,205 39,456
Spring Creek 4,616 5,072 3,625 3,788 5,161 5,502 17,101 19,106
Decker (50% interest) 395 417 384 245 473 432 1,441 1,549
Total 24,009 24,802 20,460 22,792 25,652 24,803 92,063 97,186

Copyright Business Wire 2010