Cloud Peak Energy Inc. Announces Results For The Third Quarter And First Nine Months Of 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 third quarter and first nine months of 2012.

2012 Third Quarter and Nine Months Highlights
  • Record Adjusted EBITDA(1) of $108.4 million in the third quarter of 2012 compared with $87.9 million in the third quarter of 2011; Adjusted EBITDA of $249.8 million compared with $258.8 million for the first nine months of 2011.
  • Net income of $85.3 million resulting in Adjusted EPS(1) of $0.80 compared to $0.61 in the third quarter of 2011; net income of $145.6 million resulting in Adjusted EPS of $1.62 compared to $1.78 in the first nine months of 2011.
  • Diluted EPS of $1.39 compared to $0.41 in the third quarter of 2011; diluted EPS of $2.39 compared to $2.41 in the first nine months of 2011.
  • Generated cash from operations of $202.0 million for the first nine months of 2012.
  • Shipments from the three owned and operated mines in the quarter were 24.4 million tons, level with the third quarter of 2011. For the first nine months, shipments were 67.0 million tons compared to 70.5 million tons in 2011.
  • Asian exports were up approximately 7.5% in the third quarter of 2012 to 1.5 million tons from 1.4 million tons in 2011.
  • Improved 2012 full-year guidance including increased Adjusted EBITDA expectations of $310 million to $340 million.

(1) Defined later.

“After a slower second quarter for shipments, we were pleased that the hot summer and rising natural gas prices led to stronger shipments to our customers in the third quarter. Our realized average price of $13.28 per ton was well above spot prices and continues to support our strategy of selling forward our production. In combination with good operational cost controls at the mines, this generated a record Adjusted EBITDA for the quarter of $108 million,” said Colin Marshall, President and Chief Executive Officer. “Nevertheless, current forward prices for 2013 and 2014 domestic deliveries are low, and we are managing the business accordingly. In addition, current Newcastle prices for 2013 are below 2012 levels, which will reduce our 2013 export margins.”
Operating Highlights(1)   Q3   Q3  

First NineMonths

First NineMonths
2012 2011 2012 2011
Tons sold (in millions) 24.4 24.4 67.0 70.5
Realized price per ton sold $ 13.28 $ 12.91 $ 13.24 $ 12.88
Average cost of product sold per ton $ 9.14 $ 9.17 $ 9.64 $ 9.12

(1) Includes the three company-operated mines only.

For the third quarter, sales from our three company-operated mines were 24.4 million tons, level with 24.4 million tons in the third quarter of 2011, and significantly higher than second quarter 2012 shipments of 20.1 million tons. The increase in shipments was due to increased demand as customers caught up on their committed deliveries after a strong summer burn. We shipped 1.5 million tons to our Asian customers as the Westshore Terminal operated well and the demand from our Asian utility customers remains resilient. For the third quarter 2012, the average cost of product sold was $9.14 per ton compared to $9.17 per ton in the third quarter of 2011. Good operational performance along with an increased realized price per ton of $13.28, compared to $12.91 in 2011, resulted in a margin expansion to $4.14 per ton from $3.74 per ton in the third quarter of 2011.

Health, Safety and Environment Record

During the third quarter of 2012, of our approximately 1,400 mine site employees, three suffered minor reportable injuries resulting in a year-to-date MSHA All Injury Frequency Rate of 0.73, a decrease over the full year 2011 rate of 1.18. During the 75 MSHA inspector days in the third quarter of 2012, we were issued 11 substantial and significant (S&S) citations, of which, six have been satisfactorily resolved and resulted in total proposed fines of $5,387. Fines for the remaining five S&S citations have not yet been assessed.

Balance Sheet and Cash Flow

Cash flow from operations totaled $202.0 million for the first nine months of 2012. For the nine months, cash spent on capital expenditures was $36.4 million (excluding capitalized interest) and cash spent on LBA installments was $129.2 million. This includes $60 million paid for committed coal leases in the third quarter, which was the remaining obligation for 2012. Cloud Peak Energy’s balance sheet continues to be well positioned with total available liquidity of $766 million at September 30, 2012 and no debt maturities before 2016.

Tax Receivable Agreement and Related Adjustments

During the third quarter, we completed our annual update of our life of mine operating plans and calculation of the resulting estimated future taxable income, which is used to update the undiscounted future estimated liability to Rio Tinto under the Tax Receivable Agreement. These updates resulted in a reduction of the future tax value expected to be received; and therefore, there was a decrease in the third quarter in the future estimated liability due to Rio Tinto under the Tax Receivable Agreement. A non-cash benefit of $29.0 million to non-operating income was recorded for the three months ended September 30, 2012. Changes to our estimated future taxable income also changed our projections regarding our ability to fully utilize our deferred tax assets and we have therefore made adjustments to our valuation allowance on deferred tax assets. The deferred tax adjustments relating to the change in the tax agreement liability and the valuation allowance resulted in a net $6.5 million deferred tax benefit which was recorded through income tax expense.

The coal acquired as a part of the Youngs Creek acquisition is not anticipated to be classified as proven and probable reserves at December 31, 2012; therefore, no adjustment was made to the tax agreement liability for this coal asset acquisition as we are unable to make a reasonable estimate of the expected additional taxable income resulting from the development of these assets until definitive mine plans are sufficiently advanced.


We continue to expect to export approximately 4.3 million tons for the full year 2012, 4.0 million tons of which will go through the Westshore Terminal. During the third quarter, Cloud Peak Energy shipped approximately 1.5 million tons to our Asian customers, bringing the nine-month total to 3.5 million tons. The Westshore Terminal is undergoing the second phase of their current expansion, which will increase the annual capacity from about 32 million tons to 36 million tons. We are planning on increasing our 2013 shipments in proportion to the expanded capacity to around 4.5 million tons through the Westshore Terminal.


The hot summer increased coal burn and natural gas prices, which led to stronger shipments and reductions in stockpiles of coal held by utilities. Stockpiles, while still high, are estimated to be within the five-year average. Stockpiles of PRB coal as of the end of August 2012 were at approximately 90 million tons, which is around 26 million tons above the same time last year when they were at a five-year low. The outlook for coal demand for the rest of the year will depend on the intensity and timing of the winter season and the price of natural gas.

Given the strong operating performance of the business year to date, including domestic and export shipments, and effective cost controls, we are raising our guidance for Adjusted EBITDA for 2012. We now anticipate that Adjusted EBITDA will be between $310 million and $340 million up from our previous range of $300 million to $330 million.

We continue to scrutinize capital expenditures. As a result of continuing to optimize our condition monitoring maintenance programs, we are reducing our expected capital expenditures for 2012 to between $50 million and $60 million.

For 2012, Cloud Peak Energy has committed 92.4 million tons, of which 92.0 million tons are under fixed-price agreements with a weighted-average price of $13.23 per ton. Assuming current low OTC prices for our committed but unpriced 2012 tons, our weighted-average price would be $13.20 per ton for the full year 2012. We are not expecting to make any significant additional sales for delivery in 2012 and are focusing on working with our customers to ensure delivery of their committed tonnages. During the third quarter of 2012, our committed position for 2013 increased by only 3.4 million tons to 84.6 million tons due to limited activity in the markets. Of this committed 2013 production, 74.6 million tons are under fixed-price commitments with a weighted-average price of $13.58 per ton. For 2014, we currently have 54.7 million tons committed of which 43.3 million tons are under fixed-price commitments with a weighted-average price of $14.49. If the current weak pricing environment persists through the balance of this year, the expected average realized prices for 2013 are likely to be similar to 2012.

Current Newcastle forward prices for 2013 are below 2012 levels, which will reduce our 2013 export margins. Consequently, we have not yet committed pricing on our export tons beyond the first quarter of 2013, and we will expect to lock in further pricing in the coming quarters when we are hopeful prices will rise from their current low levels. Our Newcastle hedging is providing some protection against the current low prices.

Marshall said, “We are encouraged that domestic customers are now taking their committed coal, and we are receiving fewer requests for tonnage deferrals. The hot summer and the rebound in the price of natural gas have resulted in utilities sending their trains and burning their contracted coal. We are anticipating a normal winter which should continue to draw down the stockpiles of coal and move natural gas consumption to domestic and commercial heating. Given this scenario, it is still likely that it will take until at least mid-2013 for the impact of last winter on PRB prices to be worked though so we can return to a more favorable pricing environment. However, 2012 is going well and after a record third quarter, we are raising our guidance to reflect these improvements.”

Updated Guidance – 2012 Financial and Operational Estimates

The following table provides our current outlook and assumptions for selected 2012 financial and operational metrics:
Item   Estimate or Estimated Range
Coal shipments for our three operated mines   90 - 93 million tons
Committed sales with fixed prices   Approximately 92 million tons
Anticipated realized price of produced coal with fixed prices   Approximately $13.23 per ton
Adjusted EBITDA   $310 - $340 million
Net interest expense   Approximately $36 million
Depreciation, depletion and accretion   $105 - $115 million
Effective income tax rate (1)   33 - 36%
Capital expenditures (2)   $50 - $60 million
Committed federal coal lease payments   $129 million

(1) Excluding impact of the Tax Receivable Agreement.

(2) Excluding capitalized interest, federal coal lease payments, and the acquisition of Youngs Creek.

Conference Call Details

A conference call with management is scheduled at 5:00 p.m. ET on October 25, 2012, to review the results and current business conditions. The call will be webcast live over the Internet from our Web site at under “Investor Relations.” Participants should follow the instructions provided on the Web site for downloading and installing the audio applications necessary to join the webcast. Interested individuals also can access the live conference call via telephone at 866.730.5765 (domestic) or 857.350.1589 (international) and entering pass code 44853566.

Following the live webcast, a replay will be available at the same URL on our Web site 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 57713356. 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 complimentary surface assets in the Northern PRB, further building the company’s long-term position to serve Asian export and domestic customers. With approximately 1,600 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 2012 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 capacity; (2) anticipated economic conditions and demand by domestic and foreign 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, including estimates, plans and potential future development and synergies of our recently acquired Youngs Creek assets and potential transaction with the Crow Tribe of Indians; (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; and (11) 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, export demand and terminal capacity and the prices we receive for our coal; (c) reductions or deferrals of contracted tons or future 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) risks associated with acquisitions, including not achieving anticipated synergies, increased development and operating costs, failure to develop acquired assets, termination of the coal leases from Chevron and CONSOL in the Youngs Creek transaction if we fail to meet minimum future production requirements, and our failure to enter into the potential transaction with the Crow Tribe of Indians, and (o) 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 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., or 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 for specifically identified items that management believes do not directly reflect our core operations. The specifically identified items are the impacts, as applicable, of: (1) the Tax Receivable Agreement including tax impacts of our 2009 initial public offering and 2010 secondary offering, (2) adjustments for derivative financial instruments including unrealized marked-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 tax 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. 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.




(in thousands, except per share data)
Three Months Ended Nine Months Ended
September 30, September 30,
2012   2011 2012   2011
Revenues $ 425,861   $ 406,950   $ 1,141,947   $ 1,151,174  
Costs and expenses

Cost of product sold (exclusive of depreciation, depletion, amortization and accretion, shown separately)
301,945 306,533 850,963 855,551
Depreciation and depletion 24,661 24,289 70,337 58,537
Accretion 3,257 2,984 9,327 9,420
Derivative financial instruments (1,334 ) (19,461 )
Selling, general and administrative expenses   15,698     12,971     43,397     38,905  
Total costs and expenses   344,227     346,777     954,563     962,413  
Operating income   81,634     60,173     187,384     188,761  
Other income (expense)
Interest income 189 143 948 459
Interest expense (11,671 ) (6,848 ) (25,457 ) (27,520 )
Tax agreement benefit (expense) 29,000 22,878 29,000 (19,855 )
Other, net   (335 )   (103 )   (388 )   (34 )
Total other income (expense)   17,183     16,070     4,103     (46,950 )

Income before income tax provision and earnings from unconsolidated affiliates
98,817 76,243 191,487 141,811
Income tax (expense) benefit (13,601 ) (52,162 ) (47,509 ) 2,025
Earnings from unconsolidated affiliates, net of tax   44     530     1,579     2,142  
Net income   85,260     24,611     145,557     145,978  
Other comprehensive income
Retiree medical plan amortization of prior service cost 394 326 1,272 978
Tax on amortization of prior service cost   (142 )   (117 )   (458 )   (352 )
Other comprehensive income   252     209     814     626  
Total comprehensive income $ 85,512   $ 24,820   $ 146,371   $ 146,604  
Net income per common share:
Basic $ 1.42 $ 0.41 $ 2.43 $ 2.43
Diluted $ 1.39   $ 0.41   $ 2.39   $ 2.41  
Weighted-average shares outstanding - basic   60,044     60,007     60,020     60,003  
Weighted-average shares outstanding - diluted   61,142     60,645     60,923     60,606  



(in thousands)
  September 30,   December 31,
2012 2011
ASSETS (unaudited) (audited)
Current assets
Cash and cash equivalents $ 185,505 $ 404,240
Investments in marketable securities 80,331 75,228
Restricted cash 71,245
Accounts receivable 106,300 95,247
Due from related parties 2,823 471
Inventories, net 82,083 71,648
Deferred income taxes 37,216 37,528
Derivative financial instruments 20,730 2,275
Other assets   22,114     13,019  
Total current assets   537,102     770,901  
Noncurrent assets
Property, plant and equipment, net 1,643,397 1,350,135
Goodwill 35,634 35,634
Deferred income taxes 95,044 132,828
Other assets   33,621     29,821  
Total assets $ 2,344,798   $ 2,319,319  
Current liabilities
Accounts payable $ 69,317 $ 71,427
Royalties and production taxes 144,811 136,072
Accrued expenses 53,774 65,928
Current portion of tax agreement liability 25,097 19,113
Current portion of federal coal lease obligations 63,191 102,198
Other liabilities   2,669     4,971  
Total current liabilities   358,859     399,709  
Noncurrent liabilities
Tax agreement liability, net of current portion 116,539 151,523
Senior notes 596,397 596,077
Federal coal lease obligations, net of current portion 122,928 186,119
Asset retirement obligations, net of current portion 197,732 192,707
Other liabilities   46,098     42,795  
Total liabilities   1,438,553     1,568,930  

Common stock ($0.01 par value; 200,000 shares authorized; 61,104 and 60,923 shares issued and outstanding at September 30, 2012 and December 31, 2011, respectively)
611 609
Additional paid-in capital 545,784 536,301
Retained earnings 377,650 232,093
Accumulated other comprehensive loss   (17,800 )   (18,614 )
Total equity   906,245     750,389  
Total liabilities and equity $ 2,344,798   $ 2,319,319  



(in thousands)
  Nine Months Ended
September 30,
2012   2011
Cash flows from operating activities
Net income $ 145,557 $ 145,978
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion 70,337 58,537
Accretion 9,327 9,420
Earnings from unconsolidated affiliates (1,579 ) (2,142 )
Distributions of income from unconsolidated affiliates 1,000 2,000
Deferred income taxes 36,747 (9,781 )
Tax agreement expense (29,000 ) 19,855
Stock compensation expense 9,485 6,315
Unrealized derivative income (19,461 )
Other 8,804 8,920
Changes in operating assets and liabilities:
Accounts receivable (11,052 ) (32,289 )
Inventories (9,970 ) (7,561 )
Due to or from related parties (2,351 ) (948 )
Other assets (8,608 ) (4,539 )
Accounts payable and accrued expenses 7,585 23,561
Asset retirement obligations   (4,867 )   (4,851 )
Net cash provided by operating activities   201,954     212,475  
Investing activities
Acquisition of Youngs Creek and CX Ranch coal and land assets (300,377 )
Purchases of property, plant and equipment (36,445 ) (82,050 )
Cash paid for capitalized interest (42,877 ) (18,772 )
Investments in marketable securities (58,611 )
Maturity and redemption of investments 53,508
Initial payments on federal coal leases (69,407 )
Return of restricted cash 71,244 107,887
Partnership escrow deposit (4,470 )
Other   1,847     545  
Net cash used in investing activities   (316,181 )   (61,797 )
Financing activities
Principal payments on federal coal leases (102,198 ) (50,902 )
Other   (2,310 )   (2,317 )
Net cash used in financing activities   (104,508 )   (53,219 )
Net decrease in cash and cash equivalents (218,735 ) 97,459
Cash and cash equivalents at beginning of period   404,240     340,101  
Cash and cash equivalents at end of period $ 185,505   $ 437,560  
Supplemental cash flow disclosures
Interest paid $ 57,911 $ 36,405
Non-cash interest capitalized $ 7,445 $ 17,168
Income taxes paid $ 22,017 $ 6,161



(in millions, except per share data)

Adjusted EBITDA
  Three Months Ended   Nine Months Ended
September 30, September 30,
2012   2011 2012   2011
Net income $ 85.3   $ 24.6   $ 145.6   $ 146.0  
Interest income (0.2 ) (0.1 ) (0.9 ) (0.5 )
Interest expense 11.7 6.8 25.5 27.5
Income tax expense (benefit) 13.6 52.2 47.5 (2.0 )
Depreciation and depletion 24.7 24.3 70.3 58.5
Accretion   3.3     3.0     9.3     9.4  
EBITDA $ 138.3 $ 110.8 $ 297.2 $ 238.9
Tax agreement expense(1) (29.0 ) (22.9 ) (29.0 ) 19.9
Derivative financial instruments(2) (0.9 ) (18.5 )
Expired significant broker contract                
Adjusted EBITDA $ 108.4   $ 87.9   $ 249.8   $ 258.8  

(1) Changes to related deferred taxes are included in income tax expense.

(2) Derivative financial instruments including unrealized marked-to-market amounts and cash settlements realized.

Adjusted EPS
Three Months Ended Nine Months Ended
September 30, September 30,
2012   2011 2012   2011
Diluted earnings per common share $ 1.39   $ 0.41   $ 2.39   $ 2.41  

Tax agreement expense including tax impacts of IPO and Secondary Offering
(0.58 ) 0.20 (0.58 ) (0.63 )
Derivative financial instruments(1) (0.01 ) (0.19 )
Expired significant broker contract                
Adjusted EPS $ 0.80   $ 0.61   $ 1.62   $ 1.78  

Weighted-average dilutive shares outstanding (in millions)
61.1 60.6 60.9 60.6

(1) Derivative financial instruments including unrealized mark-to-market amounts and cash settlements realized.
Tons Sold
(in thousands) Q3 Q2 Q1 Q4 Q3 Q2 Year
2012 2012 2012 2011 2011 2011 2011
Antelope 9,111 7,424 8,752 9,948 8,901 9,059 37,075
Cordero Rojo 10,201 9,027 10,007 10,070 9,968 9,225 39,456
Spring Creek 5,072 3,625 3,788 5,161 5,502 4,729 19,106
Decker (50% interest) 417 384 245 473 432 426 1,549
Total 24,802 20,460 22,792 25,653 24,803 23,439 97,186

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