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Table of Contents

As filed with the Securities and Exchange Commission on March 7, 2012.
Registration Statement No. 333-177259
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
 
Amendment No. 4
to
 
 
Form S-1
 
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
 
 
 
ARMSTRONG ENERGY, INC.
(Exact name of registrant as specified in its charter)
 
         
Delaware   1221   20-8015664
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (IRS Employer
Identification No.)
         
 
7733 Forsyth Boulevard, Suite 1625
St. Louis, Missouri 63105
(314) 721-8202
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
 
 
 
 
Martin D. Wilson
Armstrong Energy, Inc.
7733 Forsyth Boulevard, Suite 1625
St. Louis, Missouri 63105
(314) 721-8202
(Name, address, including zip code, and telephone number, including area code, of agent for service)
 
With copies to:
 
     
David W. Braswell, Esq.    D. Rhett Brandon, Esq.
Armstrong Teasdale LLP   Simpson Thacher & Bartlett LLP
7700 Forsyth Boulevard, Suite 1800   425 Lexington Avenue
St. Louis, Missouri 63105   New York, New York 10017
(314) 552-6631   (212) 455-2000
 
Approximate date of commencement of proposed sale to the public:  As soon as practicable after this Registration Statement is declared effective.
 
If any securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o
 
If this Form is filed to register additional securities for an offering pursuant to Rule 462(c) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
 
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
 
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer o Accelerated filer o Non-accelerated filer þ Smaller reporting company o
(Do not check if a smaller reporting company)
 
The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
 


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The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer of sale is not permitted.
 
 
PRELIMINARY PROSPECTUS SUBJECT TO COMPLETION, DATED MARCH 7, 2012
 
           Shares
 
ARMSTRONG ENERGY, INC.
 
Common Stock
 
 
 
 
This is the initial public offering of our common stock. We are offering           shares of our common stock, par value $0.01 per share. No public market currently exists for our common stock. We currently expect the initial public offering price to be between $      and $      per share.
 
We expect to apply to list our common stock on the Nasdaq Global Market (“Nasdaq”) under the symbol “ARMS.” There is no assurance that this application will be approved.
 
 
 
 
Investing in our common stock involves risks. You should read the section entitled “Risk Factors” beginning on page 16 for a discussion of certain risk factors that you should consider before investing in our common stock.
 
Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or passed upon the adequacy or accuracy of this registration statement. Any representation to the contrary is a criminal offense.
 
 
 
 
                 
    Per Share   Total
 
Public offering price
  $           $        
Underwriting discount
  $       $    
Offering proceeds to Armstrong Energy, Inc. before expenses
  $       $  
 
To the extent the underwriters sell more than           shares of common stock, the underwriters have an option exercisable within 30 days from the date of this prospectus to purchase up to           additional shares of common stock from us at the public offering price, less the underwriting discount. The shares of common stock issuable upon exercise of the underwriters’ over-allotment option have been registered under the registration statement of which this prospectus forms a part.
 
The underwriters expect to deliver the shares against payment in New York, New York on or about          , 2012.
 
 
 
 
Raymond James FBR
 
Prospectus, dated          , 2012


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INDEX TO FINANCIAL STATEMENTS
    F-1  
 EX-3.4
 EX-10.45
 EX-10.52
 EX-10.54
 EX-10.61
 EX-23.2
 EX-23.3
 EX-99.1
 EX-99.2
 EX-99.2
 
No dealer, salesperson or other individual has been authorized to give any information or to make any representation other than those contained in this prospectus in connection with the offer made by this prospectus and, if given or made, such information or representations must not be relied upon as having been authorized by us or the underwriters. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any securities in any jurisdiction in which such an offer or solicitation is not authorized or in which the person making such offer or solicitation is not qualified to do so, or to any person to whom it is unlawful to make such offer or solicitation. Neither the delivery of this prospectus nor any sale made hereunder shall, under any circumstances, create any implication that there has been no change in our affairs or that information contained herein is correct as of any time subsequent to the date hereof.


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ABOUT THIS PROSPECTUS
 
You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We and the underwriters are only offering to sell, and only seeking offers to buy, the common stock in jurisdictions where offers and sales are permitted.
 
The information contained in this prospectus is accurate and complete only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of our common stock by us or the underwriters. Our business, financial condition, results of operations and prospectus may have changed since that date.
 
Market data used in this prospectus has been obtained from independent industry sources and publications, as well as from research reports prepared for other purposes. The information in these reports represents the most recently available data from the relevant sources and publications and we believe remains reliable. We engaged Weir International, Inc., an independent mining and geological consultant, to prepare a report regarding estimates of our proven and probable coal reserves at December 31, 2011. In addition, we pay a subscription fee to Wood Mackenzie to obtain access to pre-prepared reports. Except with respect to payment for Weir International, Inc.’s services in this regard and the subscription fee paid to Wood Mackenzie, we did not fund and are not otherwise affiliated with any of the sources cited in this prospectus. Forward-looking information obtained from these sources is subject to the same qualifications and additional uncertainties regarding the other forward-looking statements in this prospectus.
 
Unless the context otherwise requires, the information in the prospectus (other than in the historical financial statements) assumes that the underwriters will not exercise their over-allotment option.
 
For investors outside the United States: We have not, and the underwriters have not, done anything that would permit this offering or possession or distribution of this prospectus in any jurisdiction where action for that purpose is required, other than in the United States. Persons outside the United States who come into possession of this prospectus must inform themselves, and observe any restrictions relating to, the offering of the shares of our common stock and the distribution of this prospectus outside the United States.


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PROSPECTUS SUMMARY
 
This summary highlights information contained elsewhere in this prospectus, but it does not contain all of the information that you may consider important in making your investment decision. Therefore, you should read the entire prospectus carefully, including, in particular, the “Risk Factors” section beginning on page 14 of this prospectus and the financial statements and related notes thereto included elsewhere in this prospectus.
 
As used in this prospectus, unless the context otherwise requires or indicates, references to the “Company,” “we,” “our,” and “us” are to Armstrong Energy, Inc., Armstrong Resource Partners, L.P. and their respective subsidiaries taken as a whole, after giving effect to the Reorganization referred to herein. References to “Armstrong Resource Partners” are to Armstrong Resource Partners, L.P. and its subsidiaries taken as a whole. References to “Armstrong Energy” are to Armstrong Energy, Inc. and its subsidiaries, and do not include Armstrong Resource Partners.
 
A subsidiary of Armstrong Energy, Inc. is the general partner of, and owns a 0.4% equity interest in, Armstrong Resource Partners. By virtue of Armstrong Energy, Inc.’s control of the general partner of Armstrong Resource Partners, the results of Armstrong Resource Partners are consolidated in our historical consolidated financial statements contained herein.
 
As described more fully below, concurrently with the offering of common stock of Armstrong Energy, Inc. being made pursuant to this prospectus, Armstrong Resource Partners is engaging in an offering of its limited partnership units. This prospectus relates solely to the offering of the common stock of Armstrong Energy, Inc. and does not relate to the concurrent offering by Armstrong Resource Partners, which will be made by a separate prospectus.
 
About the Company
 
We are a diversified producer of low chlorine, high sulfur thermal coal from the Illinois Basin, with both surface and underground mines. We market our coal primarily to electric utility companies as fuel for their steam-powered generators. Based on 2011 production, we are the sixth largest producer in the Illinois Basin and the second largest in Western Kentucky. We were formed in 2006 to acquire and develop a large coal reserve holding. We commenced production in the second quarter of 2008 and currently operate seven mines, including five surface and two underground, and are seeking permits for three additional mines. We control approximately 326 million tons of proven and probable coal reserves. Our reserves and operations are located in the Western Kentucky counties of Ohio, Muhlenberg, Union and Webster. We also own and operate three coal processing plants which support our mining operations. The location of our coal reserves and operations, adjacent to the Green and Ohio Rivers, together with our river dock coal handling and rail loadout facilities, allow us to optimize our coal blending and handling, and provide our customers with rail, barge and truck transportation options. From our reserves, we mine coal from multiple seams which, in combination with our coal processing facilities, enhances our ability to meet customer requirements for blends of coal with different characteristics.
 
Our revenue has increased from zero in 2007 to $299.3 million in 2011, which we achieved despite a period of recession-driven declines in U.S. demand for coal and a challenging environment in the credit markets. For the year ended December 31, 2011, we generated operating income of $7.9 million and Adjusted EBITDA of $41.0 million. Adjusted EBITDA is a non-GAAP financial measure which represents net income (loss) before net interest expense, income taxes, depreciation, depletion and amortization, non-cash stock compensation expense, non-cash charges related to non-recourse notes, gain on deconsolidation and gain on extinguishment of debt. For these purposes, “GAAP” refers to U.S. generally accepted accounting principles. Please see “— Summary Historical and Unaudited Pro Forma Consolidated Financial and Operating Data” for a reconciliation of Adjusted EBITDA to net income (loss).
 
For the year ended December 31, 2011, we produced 6.6 million tons of coal, with seven mines in operation. We currently expect a significant increase in our production for 2012 compared to 2011. We are contractually committed to sell 8.1 million tons of coal in 2012 and 8.2 million tons of coal in 2013, which


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represents 88% and 77% of our expected total coal sales in 2012 and 2013, respectively. The following table summarizes our mines, our recent production and our coal reserves as of December 31, 2011:
 
                                                                         
                                        Quality Specifications
 
          Clean Recoverable Tons
    Production     (As Received)(2)  
          (Proven and Probable
    Year
    Year
          SO2
       
          Reserves)(1)     Ended
    Ended
    Heat
    Content
       
Mines
  Mining
    Proven
    Probable
          December 31,
    December 31,
    Value
    (Lbs/
    Ash
 
(Commenced Operations)
  Method(3)     Reserves     Reserves     Total     2010     2011     (Btu/Lb)     MMBtu)     (%)  
          (In thousands)     (Tons in thousands)                    
 
Active mines
                                                                       
Midway (July 2008)
    S       19,377       1,427       20,805 (4)     1,614.8       1,589.2       11,315       4.8       10.0  
Parkway (April 2009)
    U       7,535       5,434       12,969 (4)     1,485.9       1,491.9       11,931       4.4       7.1  
East Fork (June 2009)(5)
    S       2,287       550       2,837 (4)     1,641.1       745.9       11,136       7.6       11.2  
Equality Boot (September 2010)
    S       21,841       1,151       22,992 (6)     330.8       1,916.8       11,587       5.7       8.8  
Lewis Creek (June 2011)
    S       6,160       101       6,261 (4)           474.9       11,420       4.0       9.5  
Kronos (September 2011)(7)
    U       18,810       2,995       21,805             (8)     11,792       4.5       7.6  
Maddox (November 2011)
    S       512             512 (4)           24.9       11,315       4.8       10.0  
                                                                         
Total active mines
            76,522       11,658       88,181       5,072.6       6,243.6                          
                                                                         
Additional reserves
                                                                       
Lewis Creek(7)
    U       18,810       2,995       21,805                       11,792       4.5       7.6  
Ken
    S       17,166       3,854       21,020 (4)                     11,809       5.0       7.5  
Union/Webster
    U       44,009       76,799       120,809                       12,145       4.4       8.2  
Other
    S/U       58,955       15,011       73,964 (9)     572.1 (10)     398.8 (10)     11,300       4.5       8.0  
                                                                         
Total additional reserves
            138,940       98,659       237,598                                          
                                                                         
Total
            215,462       110,317       325,779       5,644.7       6,642.4                          
                                                                         
 
 
(1) For surface mines, clean recoverable tons are based on a 90% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For underground mines other than Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.60 specific gravity and a 95% preparation plant efficiency. “Proven and probable reserves” refers to coal that can be economically extracted or produced at the time of the reserve determination.
 
(2) Quality specifications displayed on an “as received” basis, assuming 11% moisture. If derived from multiple seams, data represents an average.
 
(3) U = Underground; S = Surface
 
(4) Of these reserves, 39.45% of the interests controlled by Armstrong Energy are leased from Armstrong Resource Partners.
 
(5) Warden and Kronos pits.
 
(6) Of these reserves, 39.45% of the interests controlled by Armstrong Energy are leased from Armstrong Resource Partners. Includes approximately 0.3 million tons related to reserves for which we own or lease a 50% or more partial joint interest and royalties on extractions may be payable to other owners.
 
(7) Based on internal estimates, recoverable reserves are split evenly among the three mines that will produce coal from the underground properties and coal reserves located in Ohio County, Kentucky that are owned by Armstrong Resource Partners and leased to Armstrong Energy (the “Elk Creek Reserves”).
 
(8) The Kronos mine produced approximately 0.2 million tons of coal in 2011, but the production was capitalized and not included in our results of operations because the mine was still in the developmental phase.
 
(9) Of these reserves, 39.45% of the interests controlled by Armstrong Energy are leased from Armstrong Resource Partners. Includes approximately 1.9 million tons related to reserves for which we own or lease a 50% or more partial joint interest and royalties on extractions may be payable to other owners.
 
(10) Includes production from our Big Run mine, which ceased production in October 2011.


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The following table shows the ownership status of our reserves by mine:
 
                         
    Clean Recoverable Tons (Proven and Probable
 
Mines
  Reserves)(1)  
(Commenced Operations)
  Owned     Leased     Total  
    (In thousands)  
 
Active mines
                       
Midway (July 2008)
    20,805             20,805 (2)
Parkway (April 2009)
    2,326       10,643       12,969 (2)
East Fork (June 2009)(3)
    2,193       645       2,837 (2)
Equality Boot (September 2010)
    22,992             22,992 (4)
Lewis Creek (surface) (June 2011)
    6,261             6,261 (2)
Kronos (September 2011)(5)
    20,630       1,175       21,805  
Maddox (November 2011)
    512             512 (2)
                         
Total active mines
    75,719       12,463       88,181  
                         
Additional reserves
                       
Lewis Creek(5)
    20,630       1,175       21,805  
Ken
    21,020             21,020 (2)
Union/Webster Counties
    3,077       117,732       120,809  
Other
    56,057       17,907       73,964 (6)
                         
Total additional reserves
    100,784       136,814       237,598  
                         
Total
    176,503       149,277       325,779  
                         
 
 
(1) For surface mines, clean recoverable tons are based on a 90% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For underground mines other than Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.60 specific gravity and a 95% preparation plant efficiency. “Proven and probable reserves” refers to coal that can be economically extracted or produced at the time of the reserve determination.
 
(2) Of these reserves, 39.45% of the interests controlled by Armstrong Energy are leased from Armstrong Resource Partners.
 
(3) Warden and Kronos pits.
 
(4) Of these reserves, 39.45% of the interests controlled by Armstrong Energy are leased from Armstrong Resource Partners. Includes approximately 0.3 million tons related to reserves for which we own or lease a 50% or more partial joint interest and royalties on extractions may be payable to other owners.
 
(5) Based on internal estimates, recoverable reserves are split evenly among the three mines that comprise the Elk Creek Reserves.
 
(6) Of these reserves, 39.45% of the interests controlled by Armstrong Energy are leased from Armstrong Resource Partners. Includes approximately 1.9 million tons related to reserves for which we own or lease a 50% or more partial joint interest and royalties on extractions may be payable to other owners.
 
About Armstrong Resource Partners
 
Our affiliate, Armstrong Resource Partners, was formed to manage and lease coal properties and collect royalties in the Western Kentucky region of the Illinois Basin. Armstrong Energy holds a 0.4% equity interest in Armstrong Resource Partners through a wholly-owned subsidiary, Elk Creek GP, LLC (“Elk Creek GP”), which is the general partner of Armstrong Resource Partners. The outstanding limited partnership interests (“common units”) of Armstrong Resource Partners, representing 99.6% of its equity interests, are owned by investment funds managed by Yorktown Partners LLC (collectively, “Yorktown”). Armstrong Energy is majority-owned by Yorktown. Of our total controlled reserves of 326 million tons, 65 million tons (20%) are


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owned 100% by Armstrong Resource Partners, and 140 million tons (43%) are held by Armstrong Energy and Armstrong Resource Partners as joint tenants in common with 60.55% and 39.45% interests, respectively.
 
Armstrong Energy has entered into lease agreements with Armstrong Resource Partners pursuant to which Armstrong Resource Partners granted Armstrong Energy leases to its 39.45% undivided interest in the mining properties described above and licenses to mine coal on those properties. Armstrong Energy is obligated to pay Armstrong Resource Partners a production royalty equal to 7% of the sales price of the coal which Armstrong Energy mines from the properties, which at the option of Armstrong Energy can be deferred under circumstances which give Armstrong Resource Partners the right to acquire additional reserves from Armstrong Energy.
 
Armstrong Resource Partners has also entered into a lease and sublease agreement with Armstrong Energy relating to our Elk Creek Reserves and granted Armstrong Energy a license to mine coal on those properties. The terms of this agreement mirror those of the lease agreements described above. Armstrong Energy has paid $12 million of advance royalties under the lease, which are recoupable against production royalties.
 
See “Business — About Armstrong Resource Partners” for additional information about Armstrong Resource Partners.
 
Based upon our current estimates of production for 2012, we anticipate that Armstrong Energy will owe royalties to Armstrong Resource Partners under the above-mentioned license and lease arrangements of approximately $18.6 million in 2012, of which $8.6 million will be recoupable against the advance royalty payment referred to above.
 
Concurrent Offering
 
Concurrent with this offering of common stock, Armstrong Resource Partners is offering common units pursuant to a separate initial public offering (the “Concurrent ARP Offering”). Armstrong Energy indirectly holds a 0.4% equity interest in Armstrong Resource Partners. See “Business — Our Organizational History.” If the Concurrent ARP Offering and the related transactions between Armstrong Energy and Armstrong Resource Partners are completed, we expect to receive the net proceeds of the Concurrent ARP Offering and to transfer to Armstrong Resource Partners additional undivided interests in reserves controlled jointly by Armstrong Energy and Armstrong Resources Partners. See “— Corporate Structure” and “Certain Relationships and Related Party Transactions — Concurrent Transactions with Armstrong Resource Partners.” We expect to apply any proceeds received by Armstrong Energy from these transactions to repay borrowings under our Senior Secured Credit Facility and to use any amounts not so applied for working capital. While Armstrong Resource Partners intends to consummate the Concurrent ARP Offering simultaneously with this offering of common stock, the completion of this offering is not subject to the completion of the Concurrent ARP Offering and the completion of the Concurrent ARP Offering is not subject to the completion of this offering. This description and other information in this prospectus regarding the Concurrent ARP Offering is included in this prospectus solely for informational purposes. Nothing in this prospectus should be construed as an offer to sell, nor the solicitation of an offer to buy, any common units of Armstrong Resource Partners.
 
Coal Industry Overview
 
According to the U.S. Department of Energy’s Energy Information Administration (“EIA”), the U.S. coal industry produced approximately 1.1 billion tons of coal in 2011, a substantial majority of which was sold by U.S. coal producers to operators of electricity generation plants. Coal-fired electricity generation is the largest component of total world electricity generation. The following market dynamics and trends currently impact thermal coal consumption and production in the United States and are reshaping competitive advantages for coal producers.
 
  •  Stable long-term outlook for U.S. thermal coal market.  According to the EIA, coal-fired electricity generation accounted for approximately 44% of all electricity generation in the United States in 2011. Coal continues to be the lowest cost fossil fuel source of energy for electric power generation. Despite recent increases in generation from natural gas, as well as federal and state subsidies for the


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  construction and operation of renewable energy, the EIA projects that coal-fired generation will continue to remain the largest single source of electricity generation in 2035.
 
  •  Increasing demand for coal produced in the Illinois Basin.  According to Wood Mackenzie, a leading commodities consultancy, demand for coal produced from the Illinois Basin is expected to grow by 48% from 2010 through 2015 and by 108% from 2010 through 2030. We believe this is due to a combination of factors including:
 
  è  Significant expansion of scrubbed coal-fired electricity generating capacity.  The EIA forecasts a 32% increase in flue gas desulfurization (“FGD”) installed on the coal-fired generation fleet from 168 gigawatts in 2009 to 222 gigawatts, or 70% of all U.S. coal-fired capacity in the electric sector, by 2035 as electricity generation operators invest in retrofit emissions reduction technology to comply with new U.S. Environmental Protection Agency (“EPA”) regulations under the Cross-State Air Pollution Rule and the proposed Utility Boiler Maximum Achievable Control Technology (“MACT”) regulations. Illinois Basin coal generally has a higher sulfur content per ton than coal produced in other regions. However, we believe that FGD utilization will enable operators to use the most competitively priced coal (on a delivered cents per million Btu basis) irrespective of sulfur content, and thus lead to a strong increase in demand for Illinois Basin coal.
 
  è  Declines in Central Appalachian thermal coal production.  Wood Mackenzie forecasts that production of Central Appalachian thermal coal will continue to decline, falling from 128 million tons in 2010 to 64 million tons in 2015, due to reserve depletion, regulatory-driven decreases in Central Appalachian surface thermal coal production and more difficult geological conditions. These factors are expected to result in significantly higher mining costs and prices for Central Appalachian thermal coal. We believe this will lead to an increase in demand for thermal coal from the Illinois Basin due to its comparatively lower delivered cost to the major Eastern U.S. utilities who are currently the principal users of thermal coal from Central Appalachia.
 
  è  Growing demand for seaborne thermal coal.  Global trade in thermal coal accounted for nearly 70% of all global coal exports in 2010 and is projected to rise from 850 million tons in 2010 to 1.1 billion tons by 2016. We believe that limitations on existing global export coal supply, infrastructure constraints, relative exchange rates, coal quality and cost structure could create significant thermal coal export opportunities for U.S. coal producers, including Illinois Basin coal producers, particularly those similar to us with transportation access to both the Mississippi River and to rail connecting to Louisiana export terminals. In addition, we believe that certain domestic users of U.S. thermal coal will need to seek alternative sources of domestic supply as an increasing amount of domestic coal is sold in global export markets.
 
Strategy
 
Our primary business strategy is to maximize returns to our stockholders. Key components of this strategy include the following:
 
  •  Maintain safe mining operations and comply with environmental standards.  We consider safety to be our greatest operational priority. For the period January 1, 2011 through December 31, 2011, our underground and surface mines had non-fatal days lost incidence rates that were 50% and 100%, respectively, below the national averages for the same period. Non-fatal days lost incidence rate is an industry standard used to describe occupational injuries that result in the loss of one or more days from an employee’s scheduled work. We intend to maintain programs and policies designed to enable us to remain among the safest coal operations in the industry. We also intend to continue to implement responsible, effective environmental practices throughout our operations and reclamation activities.
 
  •  Continue to grow our production.  We intend to continue to increase our coal production in the coming years to satisfy what we believe will be an increasing demand for Illinois Basin coal. We will seek to support production growth by executing mining plans for our existing undeveloped reserves and by opportunistically acquiring additional coal reserves that are located near our current mining operations


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  or otherwise offer the potential for efficient and economical development of low-cost production to serve our primary market area. We commenced production at Lewis Creek in June 2011, at our Kronos underground mining operation in September 2011 and at our Maddox mine in November 2011, and currently expect that our 2012 production will be approximately 9.2 million tons, compared with 6.6 million tons in 2011.
 
  •  Increase and diversify coal sales to utilities with base load scrubbed power plants in our primary market area and pursue export opportunities.  We expect that the demand for Illinois Basin coal will rise as a result of an increase in power plants being retrofitted with scrubbers and the construction of new power plants throughout the Illinois Basin market area. We intend to continue to focus our marketing efforts principally on power plants in the Mid-Atlantic, Southeastern and Midwestern states that we expect will become consumers of Illinois Basin coal and to seek to diversify our customer base through a combination of multi-year coal supply agreements and sales in the spot market. As of December 31, 2011, we are contractually committed to sell 8.1 million tons of coal in 2012, and 8.2 million tons of coal in 2013, which represents 88% and 77% of our expected total coal sales in 2012 and 2013, respectively. In addition, we believe that the relative heat, ash, sulfur content and cost of our coal, combined with the accessibility of our coal mines and coal processing facilities to the Mississippi River and to rail connecting to Louisiana export terminals will provide the opportunity to export our coal to overseas customers.
 
  •  Maximize profitability by maintaining low-cost mining operations.  We operate our mines in a manner aimed at keeping our product quality high while maintaining low production costs. We seek to maximize our coal production and control our costs by continuing to improve our operating efficiency. Our efficiency is, in part, a function of the overburden ratios (the amount of surface material needed to be removed to extract coal) that exist at our surface coal mines. Our efficiency is also enhanced by our fleet of mobile mining equipment, substantially all of which is new, our use of the only draglines in Kentucky, our utilization of river coal movement, our information technology systems and our coordinated equipment utilization and maintenance management functions. We also believe that our highly experienced operating management and well-trained workforce will continue to help in identifying and implementing cost containment initiatives.
 
Competitive Strengths
 
We believe that the following competitive strengths will enable us to effectively execute our business strategy described above.
 
  •  We have a demonstrated track record for successfully completing reserve acquisitions, securing required permits, developing new mines and producing coal.  Since our formation in 2006, we have successfully acquired coal reserves and opened eight separate mines, obtained the necessary regulatory permits for the commencement of mining operations at those mines, and developed significant multi-year contractual relationships with large customers in our market area. We believe this resulted from our deep management experience and disciplined approach to the development of our operations and our focus on providing competitively priced Illinois Basin coal. We believe this will enable us to continue to grow our customer base, production, revenues and profitability.
 
  •  Our proven and probable reserves have a long reserve life and attractive characteristics.  As of December 31, 2011, we had approximately 326 million tons of clean recoverable (proven and probable) coal reserves. Our reserves include both surface and underground mineable coal residing in multiple seams which, in combination with our coal processing facilities, enhances our ability to meet customer requirements for blends of coal with different characteristics. Further, the comparatively low chlorine content of our coal relative to other Illinois Basin coal provides us with an additional competitive advantage in meeting the desired coal fuel profile of our customers.
 
  •  Our mines are conveniently located in close proximity to our existing and potential customers and have access to multiple transportation options for delivery.  Our mines are located adjacent to the Green and Ohio Rivers and near our preparation, loading and transportation facilities, providing our customers


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  with rail, barge and truck transportation options. We believe this will also enable us to sell our coal in both the domestic and export markets. Recently, we purchased an equity interest in, and upon development will have access to, a Mississippi River coal export terminal project in Plaquemines Parish, Louisiana, approximately 10 miles downstream of New Orleans. We intend to oversee the design, build-out and operation of this export coal terminal to facilitate the anticipated sale of our coal to international customers.
 
  •  We are a reliable supplier of cost competitive coal.  Our highly skilled, non-union workforce uses efficient mining practices that take advantage of economies of scale and reduce operating costs per ton in both surface and underground mining. We are among a small number of operators of large scale dragline surface production in the eastern United States, and our continuous miner underground mining operations are designed to provide operating flexibility to meet production requirements and to fulfill our coal contract specifications.
 
  •  We have a highly experienced management team with a long history of acquiring, building and operating coal businesses.  The members of our senior management team have a demonstrated track record of acquiring, building and operating coal businesses profitably and safely. In addition, members of our senior management team have significant experience managing the financial and organizational growth of businesses, including public companies.
 
Recent Developments
 
In September 2011, we commenced operations at our Kronos underground mine. We expect that our Kronos underground mine will have an annual production capacity of approximately 2.3 million tons. Development of the Kronos underground mine was completed in January 2012. In November 2011, we also commenced operations at our Maddox surface mine. Operations at our Big Run mine ended in October 2011 and operations at our Kronos pit at the East Fork mine ended in the fourth quarter of 2011.
 
In December 2011, we entered into a series of transactions with Cyprus Creek Land Resources, LLC and Cyprus Creek Land Company, LLC, each of which is an affiliate and/or subsidiary of Peabody Energy Corporation (together, “Peabody”), pursuant to which we acquired additional property near our existing and planned mines containing an estimated total of 7.7 million clean recoverable tons of coal and entered into leases for an estimated 14 million clean recoverable tons. In addition we entered into a joint venture relating to coal reserves near our Parkway mine. In connection with the joint venture, Peabody has agreed to contribute an aggregate of approximately 25 million tons of clean recoverable coal reserves located in Muhlenberg County, Kentucky, and we have agreed to contribute mining assets to the joint venture. We and Peabody have also agreed to contribute 51% and 49%, respectively, of the cash sufficient to complete the development of the mine and sufficient for down payments on mining equipment. We will manage the joint venture’s day-to-day operations and the development of the mine in exchange for a $0.50 per ton sold management fee. Peabody will receive a $0.25 per ton commission on all coal sales by the joint venture.
 
We and Peabody entered into an Asset Purchase Agreement pursuant to which we acquired from Peabody its rights and interests in certain owned and leased coal reserves located in Muhlenberg County, Kentucky, in exchange for (i) a cash payment by us of approximately $8.9 million, (ii) a promissory note in the aggregate principal amount of approximately $4.4 million, and (iii) an overriding royalty to Peabody to the extent we mine in excess of certain tonnages from the property as set forth in the Asset Purchase Agreement.
 
In December 2011, we and Midwest Coal Reserves of Kentucky, LLC, an affiliate of Peabody (“Midwest Coal”), entered into a Contract to Sell and Lease Real Estate pursuant to which we acquired from Midwest Coal its right, title and interest in and to the #9 seam coal reserves in Union County, Kentucky. In addition, Midwest Coal agreed to lease to us approximately 2,000 acres of #9 seam of coal. In consideration of the sale and lease of real property, we agreed to deliver (i) approximately $6.0 million in cash, (ii) a promissory note in the aggregate principal amount of approximately $3.0 million, and (iii) an overriding royalty of 2% of the gross selling price on each ton of coal produced and sold from the coal reserves that were purchased (thus excluding the leased coal).


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In December 2011, Armstrong Resource Partners sold 200,000 Series A convertible preferred units of limited partner interest to Yorktown in exchange for $20.0 million. Also in December 2011, we entered into a Membership Interest Purchase Agreement with Armstrong Resource Partners pursuant to which we agreed to sell to Armstrong Resource Partners, indirectly through contribution of a partial undivided interest in reserves to a limited liability company and transfer of our membership interests in such limited liability company, an additional partial undivided interest in reserves controlled by us. In exchange for our agreement to sell a partial undivided interest in those reserves, Armstrong Resource Partners paid us $20.0 million. In addition to the cash paid, certain amounts due to Armstrong Resource Partners totaling $5.7 million were forgiven by us, which resulted in aggregate consideration of $25.7 million. The partial undivided interest in additional reserves must be transferred to Armstrong Resource Partners within 90 days after delivery of the purchase price. This transaction, which is expected to close in March 2012, will result in the transfer by us of an 11.4% undivided interest in certain of our land and mineral reserves to Armstrong Resource Partners. Armstrong Resource Partners agreed to lease the newly transferred mineral reserves to us on the same terms as the February 2011 lease. We used the proceeds of this sale to fund the Muhlenberg County and Ohio County reserve acquisitions described above.
 
In January 2012, in connection with entry into the Fourth Amendment to our Senior Secured Credit Facility, we sold 300,000 shares of Series A convertible preferred stock to Yorktown in exchange for $30.0 million. We used the proceeds of the sale to repay a portion of our outstanding borrowings under the Senior Secured Revolving Credit Facility and for general corporate purposes. See “Description of Indebtedness.”
 
Corporate Structure
 
In August 2011, Armstrong Resources Holdings, LLC merged with and into Armstrong Energy, Inc., which subsequently changed its name to Armstrong Energy Holdings, Inc. Subsequently, Armstrong Land Company, LLC was converted to a C-corporation and changed its name to Armstrong Energy, Inc. effective October 1, 2011 (the “Reorganization”). In connection with the Reorganization, each owner of Armstrong Land Company, LLC received 9.25 shares of Armstrong Energy, Inc. common stock for each unit held. The following chart shows a summary of the corporate organization of Armstrong Energy, Inc. and its principal subsidiaries, after giving effect to the Reorganization, but prior to giving effect to the offering of common stock being made hereby or to the Concurrent ARP Offering.
 
(FLOW CHART)


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(1) Reserves owned solely by Armstrong Resource Partners. These include the Kronos, Lewis Creek and Ceralvo underground mines.
 
(2) Reserves controlled jointly by Armstrong Resource Partners (with a 39.45% undivided interest) and Armstrong Energy (with a 60.55% undivided interest). If the Concurrent ARP Offering and related transactions are completed, the undivided interest of Armstrong Resource Partners will increase, and the undivided interest of Armstrong Energy will decrease, based on the net proceeds of the Concurrent ARP Offering paid to Armstrong Energy and the value of the affected reserves as agreed by Armstrong Resource Partners and Armstrong Energy. See “Certain Relationships and Related Party Transactions — Concurrent Transactions with Armstrong Resource Partners.”
 
The following chart depicts the organization and ownership of Armstrong Energy, Inc. after giving effect to this offering and the Concurrent ARP Offering.
 
(FLOW CHART)
 
 
(1) Reserves owned solely by Armstrong Resource Partners. These include the Kronos, Lewis Creek and Ceralvo underground mines.
 
(2) Reserves controlled jointly by Armstrong Resource Partners (with a     % undivided interest) and Armstrong Energy (with a     % undivided interest), assuming an offering price of $      per unit, the midpoint of the price range set forth on the front cover page of the prospectus for the Concurrent ARP Offering and an estimated purchase price of $      for Armstrong Resource Partners’ additional interest in the partially owned reserves.
 
Corporate Information
 
Our principal executive offices are located at 7733 Forsyth Boulevard, Suite 1625, St. Louis, Missouri 63105 and our telephone number is (314) 721-8202. Our corporate website address is www.armstrongenergyinc.com. Information on, or accessible through, our website is not part of, or incorporated by reference in, this prospectus. We are incorporated under the laws of the State of Delaware.


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Ram Terminals, LLC
 
In June 2011, we acquired an 8.4% equity interest in Ram Terminals, LLC (“Ram”). Ram owns 600 acres of Mississippi Riverfront property approximately 10 miles south of New Orleans and intends to permit, design and construct a seaborne coal export terminal capable of servicing up to Panamax-sized bulk carriers with an annual through-put capacity of up to 6 million tons, and up to 10 million tons per year in the event of the widening of the Panama Canal. The terminal will be used to facilitate and ensure our access to international markets, as well as to handle export coal volumes of both metallurgical and thermal coal of other coal companies. One of the investment funds managed by Yorktown Partners LLC, is the controlling unitholder in Ram and will provide the funds for future capital expenditures related to the development of the site. See “— Yorktown Partners LLC”. We will be actively involved in the design and construction of the terminal and will provide accounting and bookkeeping assistance to Ram. Certain of our executive officers serve as officers of Ram.
 
Yorktown Partners LLC
 
Yorktown was formed in 1991 and has approximately $3.0 billion in assets under management. Yorktown invests exclusively in the energy industry with an emphasis on North American oil and gas production, coal mining and midstream businesses. Yorktown’s investors include university endowments, foundations, families, insurance companies and other institutional investors.
 
After giving effect to this offering, Armstrong Energy will continue to be majority-owned by Yorktown. In addition, Yorktown is represented on our board by Bryan H. Lawrence, founder and principal of Yorktown Partners LLC. As a result, Yorktown has, and can be expected to have, a significant influence in our operations, in the outcome of stockholder voting concerning the election of directors, the adoption or amendment of provisions in our charter and bylaws, the approval of mergers, and other significant corporate transactions. See “Risk Factors — Yorktown will continue to have significant influence over us, including control over decisions that require the approval of stockholders, which could limit your ability to influence the outcome of key transactions, including a change of control.”


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The Offering
 
The following summary contains basic information about this offering and the shares of our common stock and is not intended to be complete. This summary may not contain all of the information that is important to you. For a more complete understanding of this offering and the shares of our common stock, we encourage you to read this entire prospectus, including, without limitation, the sections of this prospectus entitled “Risk Factors” and “Description of Capital Stock,” and the documents attached to this prospectus.
 
Common Stock Offered by Armstrong Energy, Inc.
           shares.
 
Over-Allotment Option We have granted the underwriters an option to purchase up to an additional           shares of our common stock, equal to 15% of the shares offered in this offering, at the public offering price, less the underwriters’ discount, within 30 days after the date of this prospectus.
 
Common Stock to be Outstanding Immediately After this Offering
           shares (or           shares if the underwriters exercise in full their over-allotment option).
 
Common Stock Held by Our Existing Stockholders Immediately After this Offering
           shares (or           shares if the underwriters exercise in full their over-allotment option).
 
Use of Proceeds We expect to receive net proceeds from this offering of approximately $      million (or approximately $      million if the underwriters exercise in full their option to purchase additional shares of our common stock) after deducting estimated underwriting discounts and commissions, and after our offering expenses estimated at $      million, assuming the shares are offered at $      per share, which is the midpoint of the estimated offering price range shown on the front cover page of this prospectus. We intend to use $      million of the net proceeds from this offering to repay a portion of our outstanding borrowings under our Senior Secured Term Loan, and to use the balance to repay a portion of our outstanding borrowings under our Senior Secured Revolving Credit Facility and for general corporate purposes, including to fund capital expenditures relating to our mining operations and working capital.
 
Voting Rights Under Delaware law, each share of common stock entitles the holder to one vote.
 
Dividend Policy We do not anticipate paying cash dividends on shares of our common stock for the foreseeable future. In addition, our Senior Secured Credit Facility contains restrictions on the payment of dividends to holders of our common stock. See “Dividend Policy.”
 
Proposed Symbol ‘‘ARMS”
 
Risk Factors Investing in our common stock involves a high degree of risk. For a discussion of factors you should consider in making an investment, see “Risk Factors” beginning on page 16.
 
Conflicts of Interest Raymond James Bank, FSB, an affiliate of Raymond James & Associates, Inc., one of the underwriters in this offering, is expected to receive more than 5% of the net proceeds of this offering in connection with the repayment of our Senior Secured Term


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Loan and our Senior Secured Revolving Credit Facility. See “Use of Proceeds.” Accordingly, this offering is being made in compliance with the requirements of the Financial Industry Regulatory Authority (“FINRA”) Rule 5121. Rule 5121 requires that a “qualified independent underwriter” meeting certain standards to participate in the preparation of the registration statement and prospectus and exercise the usual standards of due diligence with respect thereto. FBR Capital Markets & Co. has agreed to act as a “qualified independent underwriter” within the meaning of FINRA Rule 5121 in connection with this offering. For more information, see “Conflicts of Interest.”
 
Risks Related to Our Business
 
Our business is subject to a number of risks of which you should be aware before making an investment decision. These risks are discussed more fully under the caption “Risk Factors,” and include but are not limited to the following:
 
  •  Coal prices are subject to change and a substantial or extended decline in prices could materially and adversely affect our profitability and the value of our coal reserves.
 
  •  Our coal mining operations are subject to operating risks that are beyond our control, which could result in materially increased operating expenses and decreased production levels and could materially and adversely affect our profitability.
 
  •  Competition within the coal industry could put downward pressure on coal prices and, as a result, materially and adversely affect our revenues and profitability.
 
  •  Decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators could adversely affect coal prices and 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. Declines in the prices at which we sell our coal could reduce our revenues and materially and adversely affect our business and results of operations.
 
  •  Our profitability depends in part upon the multi-year coal supply agreements we have with our customers. Changes in purchasing patterns in the coal industry could make it difficult for us to extend our existing multi-year coal supply agreements or to enter into new agreements in the future. In addition, our multi-year coal supply agreements subject us to renewal risks.
 
  •  The loss of, or significant reduction in purchases by, our largest customers could adversely affect our profitability.
 
  •  The amount of indebtedness we have incurred could significantly affect our business.
 
  •  The fiduciary duties of officers and directors of Elk Creek GP, as general partner of Armstrong Resource Partners, L.P., may conflict with those of officers and directors of Armstrong Energy.
 
  •  Yorktown will continue to have significant influence over us, including control over decisions that require the approval of stockholders, which could limit your ability to influence the outcome of key transactions, including a change of control.
 
  •  New regulatory requirements limiting greenhouse gas emissions and existing and potential future requirements relating to air emissions could reduce the demand for coal as a fuel source, which could cause the price and quantity of the coal we sell to decline materially.


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Summary Historical and Unaudited
Pro Forma Consolidated Financial and Operating Data
 
The following table presents our summary historical and unaudited pro forma consolidated financial and operating data for the periods indicated for Armstrong Energy, Inc. and its predecessor, Armstrong Land Company, LLC and their respective subsidiaries (our “Predecessor”). The summary historical financial data for the years ended December 31, 2009, 2010 and 2011 and the balance sheet data as of December 31, 2009, 2010 and 2011 are derived from the audited financial statements. The following unaudited pro forma consolidated financial data of Armstrong Energy, Inc. at December 31, 2011 and for the year ended December 31, 2011 are based on the historical consolidated financial statements of Armstrong Energy, Inc. and pro forma assumptions and adjustments, which are included elsewhere in this prospectus.
 
The unaudited pro forma consolidated balance sheet data at December 31, 2011 gives effect to (a) the issuance of common stock in this offering and the application of the net proceeds therefrom as described in “Use of Proceeds,” and (b) the contribution of net proceeds to Armstrong Energy, Inc. from the Concurrent ARP Offering, as if each had occurred on December 31, 2011.
 
The unaudited pro forma consolidated financial data for the fiscal year ended December 31, 2011 gives effect to (a) adjustments to interest expense as a result of the repayment of a portion of the secured promissory notes from the proceeds of this offering, and (b) net adjustments to interest expense as a result of the repayment of a portion of the secured promissory notes from the proceeds contributed from the Concurrent ARP Offering, partially offset by additional interest expense associated with an additional long-term obligation owed to Armstrong Resource Partners, as if each had occurred on January 1, 2011.
 
Historical results and unaudited pro forma consolidated financial and operating information is included for illustrative and informational purposes only and is not necessarily indicative of results we expect in future periods. You should read the following summary and unaudited pro forma financial data in conjunction with “Selected Historical Consolidated Financial and Operating Data,” “Unaudited Pro Forma Financial Information” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes appearing elsewhere in this prospectus.
 


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          Pro Forma
       
    Predecessor     Armstrong Energy, Inc.        
          Year Ended
       
    Year Ended December 31,     December 31,        
    2009     2010     2011     2011        
                      Unaudited        
    (In thousands, except per share data)  
 
Results of Operations Data
                                       
Total revenues
  $ 167,904     $ 220,625     $ 299,270     $                
Costs and expenses
    166,686       201,473       291,335                  
                                         
Operating income (loss)
    1,218       19,152       7,935                  
Interest expense
    (12,651 )     (11,070 )     (10,839 )                
Other income (expense), net
    988       87       278                  
Gain on extinguishment of debt
                6,954                  
                                         
Income (loss) before income taxes
    (10,445 )     8,169       4,328                  
Income tax provision
                (856 )                
                                         
Net income (loss)
    (10,445 )     8,169       3,472                  
Less: net income (loss) attributable to non-controlling interest
    (1,730 )     3,351       7,448                  
                                         
Net income (loss) attributable to common stockholders
  $ (8,715 )   $ 4,818     $ (3,976 )   $          
                                         
Earnings (loss) per share, basic and diluted
  $ (0.50 )   $ 0.25     $ (0.21 )   $          
                                         
Balance Sheet Data (at period end)
                                       
Total assets
  $ 450,618     $ 478,038     $ 507,908                  
Working capital
    (17,749 )     2,905       (30,629 )                
Total debt (including capital leases)
    159,730       139,871       244,810       (2 )        
Total stockholders’ equity
    255,333       296,681       168,138                  
Other Data
                                       
Tons sold (unaudited)
    4,674       5,387       7,030                  
Net cash provided by (used in):
                                       
Operating activities
  $ 3,054     $ 37,194     $ 48,174                  
Investing activities
    (62,476 )     (41,755 )     (75,827 )                
Financing activities
    64,854       (3,935 )     39,132                  
Adjusted EBITDA(1) (unaudited)
    16,567       41,099       41,023                  
Adjusted EBITDA is calculated as follows (unaudited):
                                       
Net income (loss)
  $ (10,445 )   $ 8,169     $ 3,472     $            
Income tax provision
                856                  
Depreciation, depletion and amortization
    14,464       21,979       31,666                  
Interest expense, net
    12,482       10,872       10,694          (3)        
Non-cash stock compensation expense
    66       79       1,383                  
Non-cash charge related to non-recourse notes
                217                  
Gain on deconsolidation
                (311 )                
Gain on extinguishment of debt
                (6,954 )                
                                         
    $ 16,567     $ 41,099     $ 41,023     $          
                                         
 
 
(1) Adjusted EBITDA is a non-GAAP financial measure, and when analyzing our operating performance, investors should use Adjusted EBITDA in addition to, and not as an alternative for, operating income and net income (loss) (each as determined in accordance with GAAP). We use Adjusted EBITDA as a supplemental financial measure. Adjusted EBITDA is defined as net income (loss) before net interest expense, income taxes, depreciation, depletion and amortization, non-cash stock compensation expense, non-cash charges related to non-recourse notes, gain on deconsolidation, and gain on extinguishment of debt.
 
Adjusted EBITDA, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. There are significant limitations to using Adjusted EBITDA as a measure of performance, including the

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inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDA reported by different companies, and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP.
 
For example, Adjusted EBITDA does not reflect:
 
• cash expenditures, or future requirements, for capital expenditures or contractual commitments; changes in, or cash requirements for, working capital needs;
 
• the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt; and
 
• any cash requirements for assets being depreciated and amortized that may have to be replaced in the future.
 
Adjusted EBITDA does not represent funds available for discretionary use because those funds are required for debt service, capital expenditures, working capital and other commitments and obligations. However, our management team believes Adjusted EBITDA is useful to an investor in evaluating our company because this measure:
 
• is widely used by investors in our industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; and
 
• helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure, which is useful for trending, analyzing and benchmarking the performance and value of our business.
 
(2) Included within pro forma total debt is $      related to the financing arrangement with Armstrong Energy, whereby Armstrong Resource Partners acquired an undivided interest in certain of the land and mineral reserves of Armstrong Energy.
 
(3) Included within pro forma interest expense, net is $      for the year ended December 31, 2010 related to interest expense associated with the financing arrangement with Armstrong Energy, whereby Armstrong Resource Partners acquired an undivided interest in certain of the land and mineral reserves of Armstrong Energy.


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RISK FACTORS
 
An investment in our common stock involves significant risks. In addition to matters described elsewhere in this prospectus, you should carefully consider the following risks involved with an investment in our common stock. You are urged to consult your own legal, tax or financial counsel for advice before making an investment decision. The occurrence of any one or more of the following could materially adversely affect an investment in our common stock or our business and operating results. If that occurs, the value of our common stock could decline and you could lose some or all of your investment.
 
Risks Related to Our Business
 
Coal prices are subject to change and a substantial or extended decline in prices could materially and adversely affect our profitability and the value of our coal reserves.
 
Our profitability and the value of our coal reserves depend upon the prices we receive for our coal. The contract prices we may receive in the future for coal depend upon factors beyond our control, including the following:
 
  •  the domestic and foreign supply and demand for coal;
 
  •  the relative cost, quantity and quality of coal available from competitors;
 
  •  competition for production of electricity from non-coal sources, which are a function of the price and availability of alternative fuels, such as natural gas, fuel oil, nuclear, hydroelectric, wind, biomass and solar power, and the location, availability, quality and price of those alternative fuel sources;
 
  •  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 limiting carbon emissions or providing for increased funding and incentives for 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 and other pollution control technologies or by other means;
 
  •  adverse weather, climatic or other natural conditions, including natural disasters;
 
  •  domestic and foreign economic conditions, including economic slowdowns;
 
  •  the proximity to, capacity of and cost of, transportation, port and unloading facilities; and
 
  •  market price fluctuations for sulfur dioxide emission allowances.
 
A substantial or extended decline in the prices we receive for our future coal sales contracts or on the spot market could materially and adversely affect us by decreasing our profitability and the value of operating our coal reserves.
 
Our coal mining operations are subject to operating risks that are beyond our control, which could result in materially increased operating expenses and decreased production levels and could materially and adversely affect our profitability.
 
We mine coal both at underground and at surface mining operations. Certain factors beyond our control, including those listed below, could disrupt our coal mining operations, adversely affect production and shipments and increase our operating costs:
 
  •  poor mining conditions resulting from geological, hydrologic or other conditions that may cause instability of mining portals, highwalls or spoil piles or cause damage to mining equipment, nearby infrastructure or mine personnel;
 
  •  delays or challenges to and difficulties in obtaining or renewing permits necessary to produce coal or operate mining or related processing and loading facilities;


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  •  adverse weather and natural disasters, such as heavy rains or snow, flooding and other natural events affecting operations, transportation or customers;
 
  •  a major incident at the mine site that causes all or part of the operations of the mine to cease for some period of time;
 
  •  mining, processing and plant equipment failures and unexpected maintenance problems;
 
  •  unexpected or accidental surface subsidence from underground mining;
 
  •  accidental mine water discharges, fires, explosions or similar mining accidents; and
 
  •  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.
 
If any of these conditions or events occurs, we could experience a delay or halt of production or shipments or our operating costs could increase significantly.
 
Competition within the coal industry could put downward pressure on coal prices and, as a result, materially and adversely affect our revenues and profitability.
 
We compete with numerous other coal producers in the Illinois Basin and in other coal producing regions of the United States, primarily Central Appalachia and the Powder River Basin. The most important factors on which we compete are:
 
  •  delivered price (i.e., the cost of coal delivered to the customer on a cents per million Btu basis, including transportation costs, which are generally paid by our customers either directly or indirectly);
 
  •  coal quality characteristics (primarily heat, sulfur, ash and moisture content); and
 
  •  reliability of supply.
 
Our competitors may have, among other things, greater liquidity, greater access to credit and other financial resources, newer or more efficient equipment, lower cost structures, partnerships with transportation companies or more effective risk management policies and procedures. Our failure to compete successfully could have a material adverse effect on our business, financial condition or results of operations.
 
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 outside our control, including the overall demand for electricity in foreign markets, currency exchange rates, ocean freight rates, port and shipping capacity, the demand for foreign-priced 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 in both U.S. and foreign markets. Foreign demand for U.S. coal has increased in recent periods. If foreign demand for U.S. coal were to decline, this decline could cause competition among coal producers for the sale of coal in the United States to intensify, potentially resulting in significant downward pressure on domestic coal prices.
 
Decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators could adversely affect coal prices and materially and adversely affect our results of operations.
 
Our coal is used primarily as fuel for electricity generation. Overall economic activity and the associated demand for power by industrial users can have significant effects on overall electricity demand. An economic slowdown can significantly slow the growth of electrical demand and could result in contraction of demand for coal. Declines in international prices for coal generally will impact U.S. prices for coal. During the past several years, international demand for coal has been driven, in significant part, by increases in demand due to economic growth in emerging markets, including China and India. Significant declines in the rates of economic growth in these regions could materially affect international demand for U.S. coal, which may have an adverse effect on U.S. coal prices.
 
Our business is closely linked to domestic demand for electricity and any changes in coal consumption by U.S. electric power generators would likely impact our business over the long term. In 2011, we sold a


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substantial majority of our coal to domestic electric power generators, and we have multi-year coal supply agreements in place with electric power generators for a significant portion of our future production. The amount of coal consumed by electric power generation is affected by, among other things:
 
  •  general economic conditions, particularly those affecting industrial electric power demand, such as the downturn in the U.S. economy and financial markets in 2008 and 2009;
 
  •  environmental and other governmental regulations, including those impacting coal-fired power plants;
 
  •  energy conservation efforts and related governmental policies; and
 
  •  indirect competition from alternative fuel sources for power generation, such as natural gas, fuel oil, nuclear, hydroelectric, wind, biomass and solar power, and the location, availability, quality and price of those alternative fuel sources, and government subsidies for those alternative fuel sources.
 
According to the EIA, total electricity consumption in the United States decreased by 0.6% during 2011 compared with 2010, and U.S. electric generation from coal decreased by 5.5% in 2011 compared with 2010. Decreases in the demand for electricity could take place in the future, such as decreases that could be caused by a worsening of current economic conditions, a prolonged economic recession or other similar events, could have a material adverse effect on the demand for coal and on our business over the long term.
 
Changes in the coal industry that affect our customers, such as those caused by decreased electricity demand and increased competition, could also adversely affect our business. Indirect competition from gas-fired plants that are cheaper to construct and easier to permit has the most potential to displace a significant amount of coal-fired generation in the near term, particularly older, less efficient coal-powered generators. In addition, uncertainty caused by federal and state regulations could cause coal customers to be uncertain of their coal requirements in future years, which could adversely affect our ability to sell coal to our customers under multi-year coal supply agreements.
 
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. 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. Declines in the prices at which we sell our coal could reduce our revenues and materially and adversely affect our business and results of operations.
 
In 2011, a substantial majority of the tons we sold were to domestic electric power generators. 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, biomass and solar power; and
 
  •  technological developments, including those related to alternative energy sources.
 
Gas-fired electricity 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 electricity generation may be fueled by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain as natural gas-fired plants are seen as having a lower environmental impact than coal-fired plants. In addition, state and federal mandates for increased use of electricity from renewable energy sources could have an adverse impact on the market for our coal. Many states have 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 energy portfolio standard in the U.S., although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy


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sources could make these sources more competitive with coal. Any reduction in the amount of coal consumed by domestic 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.
 
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. The estimates of our reserves are based on engineering, economic and geological data assembled, analyzed and reviewed by internal and third-party engineers and consultants. We update our estimates of the quantity and quality of proven and probable coal reserves periodically 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, including many factors beyond our control, including the following:
 
  •  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, 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, including the cost of reclamation bonds.
 
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.
 
Increases in the costs of mining and other industrial supplies, including steel-based supplies, diesel fuel, rubber tires and explosives, or the inability to obtain a sufficient quantity of those supplies, may adversely affect our operating costs or disrupt or delay our production.
 
Our coal mining operations use significant amounts of steel, electricity, diesel fuel, explosives, rubber tires and other mining and industrial supplies. The cost of roof bolts we use in our underground mining operations depends on the price of scrap steel. We also use significant amounts of diesel fuel and tires for the trucks and other heavy machinery we use. If the prices of mining and other industrial supplies, particularly steel-based supplies, diesel fuel and rubber tires, increase, our operating costs may be adversely affected. In addition, if we are unable to procure these supplies, our coal mining operations may be disrupted or we could experience a delay or halt in our production.
 
A defect in title or the loss of a leasehold interest in certain property could limit our ability to mine our coal reserves or result in significant unanticipated costs.
 
We conduct part of our coal mining operations on properties that we lease. A title defect or the loss of a lease could adversely affect our ability to mine the associated coal reserves. We may not verify title to our


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leased properties or associated coal reserves until we have committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. As such, the title to property that we intend to lease or coal reserves that we intend to mine may contain defects prohibiting our ability to conduct mining operations. Similarly, our leasehold interests may be subject to superior property rights of other third parties or to royalties owed to those third parties. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and require us to pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.
 
We outsource certain aspects of our business to third party contractors, which subjects us to risks, including disruptions in our business.
 
We contract with third parties to provide blasting services at all of our mines and loading services at our barge loadout facility located on the Green River. In addition, we contract with third parties to provide truck transportation services between our mines and our preparation plants. Accordingly, we are subject to the risks associated with the contractors’ ability to successfully provide the necessary services to meet our needs. If the contractors are unable to adequately provide the contracted services, and we are unable to find alternative service providers in a timely manner, our ability to conduct our coal mining operations and deliver coal to our customers may be disrupted.
 
The availability and reliability of transportation facilities and fluctuations in transportation costs could affect the demand for our coal or impair our ability to supply coal to our customers.
 
We depend upon barge, rail and truck transportation systems to deliver coal to our customers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could impair our ability to supply coal to our customers. In addition, increases in transportation costs, including the price of gasoline and diesel fuel, could make coal a less competitive source of energy when compared to alternative fuels or could make coal produced in one region of the United States less competitive than coal produced in other regions of the United States or abroad. If transportation of our coal is disrupted or if transportation costs increase significantly and we are unable to find alternative transportation providers, our coal mining operations may be disrupted, we could experience a delay or halt of production or our profitability could decrease significantly.
 
Our profitability depends in part upon the multi-year coal supply agreements we have with our customers. Changes in purchasing patterns in the coal industry could make it difficult for us to extend our existing multi-year coal supply agreements or to enter into new agreements in the future.
 
We sell a majority of our coal under multi-year coal supply agreements. Under these arrangements, we fix the prices of coal shipped during the initial year and may adjust the prices in later years. As a result, at any given time the market prices for similar-quality coal may exceed the prices for coal shipped under these arrangements. Changes in the coal industry may cause some of our customers not to renew, extend or enter into new multi-year coal supply agreements with us or to enter into agreements to purchase fewer tons of coal than in the past or on different terms or prices. In addition, uncertainty caused by federal and state regulations, including the Clean Air Act, could deter our customers from entering into multi-year coal supply agreements.
 
Because we sell a majority of our coal production under multi-year coal supply agreements, our ability to capitalize on more favorable market prices may be limited. Conversely, at any given time we are subject to fluctuations in market prices for the quantities of coal that we are planning to produce but which we have not committed to sell. As described above under “Coal prices are subject to change and a substantial or extended decline in prices could materially and adversely affect our profitability and the value of our coal reserves,” the market prices for coal may be volatile and may depend upon factors beyond our control. Our profitability may be adversely affected if we are unable to sell uncommitted production at favorable prices or at all. For more information about our multi-year coal supply agreements, you should see the section entitled “Business — Sales and Marketing — Multi-Year Coal Supply Agreements.”


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Our multi-year coal supply agreements subject us to renewal risks.
 
We sell most of the coal we produce under multi-year coal supply agreements. As a result, our results of operations are dependent upon the prices we receive for the coal we sell under these contracts. To the extent we are not successful in renewing, extending or renegotiating our multi-year coal supply agreements on favorable terms, we may have to accept lower prices for the coal we sell or sell reduced quantities of coal in order to secure new sales contracts for our coal.
 
Prices and quantities under our multi-year coal supply agreements are generally based on expectations of future coal prices at the time the contract is entered into, renewed, extended or reopened. The expectation of future prices for coal depends upon factors beyond our control, including the following:
 
  •  domestic and foreign supply and demand for coal;
 
  •  domestic demand for electricity, which tends to follow changes in general economic activity;
 
  •  domestic and foreign economic conditions;
 
  •  the price, quantity and quality of other coal available to our customers;
 
  •  competition for production of electricity from non-coal sources, including the price and availability of alternative fuels and other sources, such as natural gas, fuel oil, nuclear, hydroelectric, wind biomass and solar power, and the effects of technological developments related to these non-coal 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 and other pollution control technologies, purchasing emissions allowances or other means; and
 
  •  legislative and judicial developments, regulatory changes, or changes in energy policy and energy conservation measures that would adversely affect the coal industry.
 
For more information regarding our major customers and multi-year coal supply agreements, see “Business — Sales and Marketing.”
 
The loss of, or significant reduction in purchases by, our largest customers could adversely affect our profitability.
 
For the year ended December 31, 2011, we derived approximately 63% of our total coal revenues from sales to our two largest customers — Louisville Gas and Electric (“LGE”) and Tennessee Valley Authority (“TVA”). For the fiscal year ended December 31, 2011, coal sales to LGE and TVA constituted approximately 35% and 28% of our total coal revenues, respectively. Our multi-year coal supply agreements with LGE expire in 2015 and 2016, and our multi-year coal supply agreements with TVA expire in 2013 and 2018; however, most of our multi-year coal supply agreements with LGE and TVA contain reopener provisions pursuant to which either party can request reopening to renegotiate price and other terms for the remaining term of such agreement, and, subsequent to any such reopening, the failure to reach an agreement can lead to the termination of such agreement. In addition, one of our multi-year coal supply agreements with TVA provides that, commencing on July 1, 2011, TVA has the unilateral right to terminate the agreement upon 60 days’ written notice, in which case TVA is required to pay us a termination fee equal to 10% of the base price multiplied by the remaining number of tons to be delivered under the agreement. If our multi-year coal supply agreements with LGE or TVA are terminated early pursuant to the reopener provisions, or we fail to extend or renew our multi-year coal supply agreements with LGE or TVA, our business and results of operations could be materially and adversely affected. Even if we are able to extend or renew our multi-year coal supply agreements with LGE and TVA, if market prices for coal such agreements are low at the time of such extensions or renewals or increases in costs during the term of such extended or renewed agreements are greater than the offsets from our cost pass-through and inflation adjustment provisions under such extended or renewed agreements, our business and results of operations could be materially and adversely affected.


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Our multi-year coal supply agreements typically contain force majeure provisions allowing the parties to temporarily suspend performance during specified events beyond their control. Most of our multi-year coal supply agreements also contain provisions requiring us to deliver coal that satisfies certain quality specifications, such as heat value, sulfur content, ash content, chlorine content, hardness and ash fusion temperature. These provisions in our multi-year coal supply agreements could result in negative economic consequences to us, including price adjustments, purchasing replacement coal in a higher-priced open market, the rejection of deliveries or, in the extreme, contract termination. Our profitability may be negatively affected if we are unable to seek protection during adverse economic conditions or if we incur financial or other economic penalties as a result of the provisions of our multi-year coal supply agreements.
 
If our multi-year coal supply agreements with LGE or TVA are terminated or if we fail to extend or renew our multi-year coal supply agreements with LGE or TVA, we may be unable to timely replace such agreements. In such a case, our business and results of operations could be materially and adversely affected.
 
Our assets and operations are concentrated in Western Kentucky and the Illinois Basin, and a disruption within that geographic region could adversely affect the Company’s performance.
 
We rely exclusively on sales generated from products distributed from the terminals we own, which are exclusively located in the Illinois Basin and Western Kentucky. Due to our lack of diversification in geographic location, an adverse development in these areas, including adverse developments due to catastrophic events or weather and decreases in demand for coal or electricity, could have a significantly greater adverse impact on our ability to operate our business and our results of operations than if we held more diverse assets and locations.
 
The amount of indebtedness we have incurred could significantly affect our business.
 
At December 31, 2011, we had consolidated long-term indebtedness of approximately $159.7 million, which is comprised of the following: $100.0 million in borrowings under the Senior Secured Term Loan, $40.0 million in borrowings under the Senior Secured Revolving Credit Facility, and $19.7 million in other long-term debt. As of December 31, 2011, we had a long-term obligation owed to Armstrong Resource Partners associated with the financing transaction in connection with the transfer of an undivided interest in certain land and mineral reserves to Armstrong Resource Partners totaling $71.0 million. We also have significant lease and royalty obligations, including, but not limited to, our capital lease obligations that totaled approximately $14.1 million as of December 31, 2011 and our obligations under non-cancelable operating leases that totaled approximately $53.4 million. Future minimum advance royalties totaled approximately $4.0 million as of December 31, 2011. In addition to advance royalties, production royalties are payable based on the quantity of coal minded in future years and prospective changes to mine plans. Our ability to satisfy our debt, lease and royalty obligations, and our ability to refinance our indebtedness, will depend upon our future operating performance. Our ability to satisfy our financial obligations may be adversely affected if we incur additional indebtedness in the future. In addition, the amount of indebtedness we have incurred could have significant consequences to us, such as:
 
  •  limiting our ability to obtain additional financing to fund growth, working capital, capital expenditures, debt service requirements or other cash requirements;
 
  •  exposing us to the risk of increased interest costs if the underlying interest rates rise;
 
  •  limiting our ability to invest operating cash flow in our business due to existing debt service requirements;
 
  •  making it more difficult to obtain surety bonds, letters of credit or other financing, particularly during weak credit markets;
 
  •  causing a decline in our future credit ratings;
 
  •  limiting our ability to compete with companies that are not as leveraged and that may be better positioned to withstand economic downturns;


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  •  limiting our ability to acquire new coal reserves and/or 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 compete and general economic and market conditions.
 
If we further increase our indebtedness, the related risks that we now face, including those described above, could intensify. In addition to the principal repayments on our outstanding debt, we have other demands on our cash resources, including capital expenditures and operating expenses. Our ability to pay our debt depends upon our operating performance. In particular, economic conditions could cause our revenues to decline, and hamper our ability to repay our 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 or reduce our spending. We may not be able to, at any given time, refinance our debt or sell assets on terms acceptable to us or at all.
 
We may be unable to comply with restrictions imposed by our Senior Secured Credit Facility and other financing arrangements.
 
The agreements governing our outstanding financing arrangements impose a number of restrictions on us. For example, the terms of our Senior Secured Credit Facility, leases and other financing arrangements contain financial and other covenants that create limitations on our ability to, among other things:
 
  •  borrow the full amount under our Senior Secured Credit Facility;
 
  •  effect acquisitions or dispositions;
 
  •  pay dividends or distributions;
 
  •  make certain investments;
 
  •  incur certain liens or permit them to exist;
 
  •  enter into certain types of transactions with affiliates;
 
  •  transfer or otherwise dispose of assets; and
 
  •  incur additional debt.
 
They also require us to maintain certain financial ratios and comply with various other financial covenants. Our ability to comply with these restrictions may be affected by events beyond our control. A failure to comply with these restrictions could adversely affect our ability to borrow under our Senior Secured Credit Facility or result in an event of default under these agreements. In the event of a default, our lenders and the counterparties to our other financing arrangements could terminate their commitments to us and declare all amounts borrowed, together with accrued interest and fees, immediately due and payable. If this were to occur, we may not be able to pay these amounts, or we may be forced to seek an amendment to our financing arrangements, which could make the terms of these arrangements more onerous for us. As a result, a default under our existing or future financing arrangements could have significant consequences for us. For more information about some of the restrictions contained in our Senior Secured Credit Facility, leases and other financial arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
 
Our certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or prospects.
 
Our certificate of incorporation provides that we will renounce any interest or expectancy in, or in being offered an opportunity to participate in, any business opportunity that may be from time to time presented to (i) members of our board of directors who are not our employees, (ii) their respective employers and (iii) affiliates of the foregoing (other than us and our subsidiaries), other than opportunities expressly presented to such directors solely in their capacity as our director. This provision will apply even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to


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do so. Furthermore, no such person will be liable to us for breach of any fiduciary duty, as a director or otherwise, by reason of the fact that such person pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity. None of such persons or entities will have any duty to refrain from engaging directly or indirectly in the same or similar business activities or lines of business as us or any of our subsidiaries. See “Description of Capital Stock.”
 
For example, affiliates of our non-employee directors may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they have invested or advise, in which case we may not become aware of or otherwise have the ability to pursue such opportunities. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing our interest and expectancy in any business opportunity that may be, from time to time, presented to such persons or entities could adversely impact our business or prospects if attractive business opportunities are procured by such persons or entities for their own benefit rather than for ours.
 
The general partner of Armstrong Resource Partners, L.P. may be removed or control of Armstrong Resource Partners, L.P. may be otherwise transferred to a third party without the consent of holders of our common stock.
 
Armstrong Resource Partners is majority-owned by Yorktown. Pursuant to the ARP LPA, Yorktown may remove our subsidiary, Elk Creek GP, as general partner of Armstrong Resource Partners, L.P. or otherwise cause a change of control of Armstrong Resource Partners, L.P. without our consent or the consent of the holders of our common stock. If such a change in control of Armstrong Resource Partners, L.P. were to occur, our ability to enter into, or obtain renewals of, coal lease or mining license agreements with Armstrong Resource Partners, L.P. could be adversely affected. We may then have to seek alternative agreements or arrangements with unrelated parties and such alternative agreements or arrangements may not be available or may be on less favorable terms.
 
Some officers of Armstrong Energy may spend a substantial amount of time managing the business and affairs of Armstrong Resource Partners and its affiliates other than us.
 
These officers may face a conflict regarding the allocation of their time between our business and the other business interests of Armstrong Resource Partners. Armstrong Energy intends to cause its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs, notwithstanding that our business may be adversely affected if the officers spend less time on our business and affairs than would otherwise be available as a result of such officers’ time being split between the management of Armstrong Energy and of Armstrong Resource Partners.
 
The fiduciary duties of officers and directors of Elk Creek GP, as general partner of Armstrong Resource Partners, L.P., may conflict with those of officers and directors of Armstrong Energy.
 
As the general partner of Armstrong Resource Partners, L.P., our subsidiary Elk Creek GP has a legal duty to manage Armstrong Resource Partners, L.P. in a manner beneficial to the limited partners of Armstrong Resource Partners, L.P. This legal duty originates in Delaware statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, because Elk Creek GP is owned by Armstrong Energy, the officers and directors of Elk Creek GP also have fiduciary duties to manage the business of Elk Creek GP and Armstrong Resource Partners, L.P. in a manner beneficial to Armstrong Energy. The board of directors of Elk Creek GP, which includes some of the directors and executive officers of Armstrong Energy, Inc., may resolve any conflict between the interests of Armstrong Energy, Inc. and our stockholders, on the one hand, and Armstrong Resource Partners, L.P. and its unit holders, on the other hand, and has broad latitude to consider the interests of all parties to the conflict.
 
Conflicts of interest may arise between Armstrong Energy, Inc. and Armstrong Resource Partners, L.P. with respect to matters such as the allocation of opportunities to acquire coal reserves in the future, the terms


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and amount of any related royalty payments, whether and to what extent Armstrong Resource Partners, L.P. may borrow under our Senior Secured Credit Agreement or other borrowing facilities we may enter into and other matters. Armstrong Energy may continue to provide credit support to Armstrong Resource Partners to support borrowings it may make in connection with any acquisition of reserves or for other purposes, including the funding of distributions to its unit holders. In addition, we may determine to permit Armstrong Resource Partners to engage in other activities, including the acquisition of coal reserves that will not be used by Armstrong Energy.
 
As a result of these relationships, conflicts of interest may arise in the future between Armstrong Energy, Inc. and its stockholders, on the one hand, and Armstrong Resource Partners, L.P. and its unit holders, on the other hand.
 
We have established a conflicts committee comprised of independent directors of Armstrong Energy to address matters which Armstrong Energy’s board of directors believes may involve conflicts of interest. See “Management” and “Management — Board of Directors and Board Committees — Conflicts Committee.”
 
Armstrong Energy’s board of directors may change the management and allocation policies relating to Armstrong Resource Partners without the approval of our stockholders.
 
Armstrong Energy’s board of directors has adopted certain management and allocation policies to serve as guidelines in making decisions regarding the relationships between and among Armstrong Energy and Armstrong Resource Partners with respect to matters such as tax liabilities and benefits, inter-group loans, inter-group interests, financing alternatives, corporate opportunities and similar items. These policies are not included in our certificate of incorporation or by-laws and our board of directors may at any time change or make exceptions to these policies. Because these policies relate to matters concerning the day to day management of our company, no stockholder approval is required with respect to their adoption or amendment. A decision to change, or make exceptions to, these policies or adopt additional policies could disadvantage Armstrong Energy or its stockholders.
 
Holders of shares of our common stock may not have any remedies if any action by our directors or officers in relation to Armstrong Resource Partners has an adverse effect on only Armstrong Energy common stock.
 
Principles of Delaware law and the provisions of the certificate of incorporation and by-laws may protect decisions of our board of directors in relation to Armstrong Resource Partners that have a disparate impact upon holders of shares of common stock of Armstrong Energy. Under the principles of Delaware law and the Delaware business judgment rule, you may not be able to successfully challenge decisions in relation to Armstrong Resource Partners that you believe have a disparate impact upon the holders of shares of our common stock of Armstrong Energy if its board of directors is disinterested and independent with respect to the action taken, is adequately informed with respect to the action taken and acts in good faith and in the honest belief that the board is acting in the best interest of stockholders.
 
Our capital structure may inhibit or prevent acquisition bids for our company.
 
The fact that substantially all of the economic value of the equity interests in Armstrong Resource Partners is expected to be owned by persons or entities other than us or our controlled affiliates could present complexities and in certain circumstances pose obstacles, financial and otherwise, to an acquiring person that are not present in companies which do not have capital structures similar to ours.
 
Yorktown will continue to have significant influence over us, including control over decisions that require the approval of stockholders, which could limit your ability to influence the outcome of key transactions, including a change of control.
 
After giving effect to this offering, Yorktown is expected to beneficially own approximately     % of our outstanding common stock (or     % if the underwriters exercise their option to purchase additional shares in full). As a result, Yorktown will retain the ability to direct and control our business affairs. Yorktown has


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influence over our decisions to enter into any corporate transaction regardless of whether others believe that the transaction is in our best interests. As long as Yorktown continues to hold a large portion of our outstanding common stock, it also will have the ability to influence the vote in any election of directors.
 
Yorktown is also in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us. Yorktown may also pursue acquisition opportunities that are complementary to our business, and, as a result, those acquisition opportunities may not be available to us. As long as Yorktown, or other funds controlled by or associated with Yorktown, continue to indirectly own a significant amount of our outstanding common stock, Yorktown will continue to be able to strongly influence or effectively control our decisions. The concentration of ownership may have the effect of delaying, preventing or deterring a change of control of our company, could deprive stockholders of an opportunity to receive a premium for their common stock as part of a sale of our company and might ultimately affect the market price of our common stock.
 
Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal.
 
Federal and state laws require us to obtain surety bonds to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other obligations. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including letters of credit or other terms less favorable to us upon those renewals. Because we are required by state and federal law to have these bonds in place before mining can commence or continue, 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 on collateral for current and future third party surety bond issuers under the terms of our financing arrangements.
 
Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel.
 
Our ability to operate our business and implement our strategies depends on the continued contributions of our executive officers and key employees. In particular, we depend significantly on our senior management’s long-standing relationships within our industry. The loss of any of our senior executives could have a material adverse effect on our business. In addition, we believe that our future success will depend on our continued ability to attract and retain highly skilled management personnel with coal industry experience and competition for these persons in the coal industry is intense. We may not be able to continue to employ key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract key personnel could have a material adverse effect on our ability to effectively operate our business.
 
We are subject to various legal proceedings, which may have an adverse effect on our business.
 
We are involved in a number of threatened and pending legal proceedings incidental to our normal business activities. While we cannot predict the outcome of the proceedings, there is always the potential that the costs of litigation in an individual matter or the aggregation of many matters could have an adverse effect on our cash flows, results of operations or financial position.
 
A shortage of skilled labor in the mining industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.
 
Efficient coal mining using modern techniques and equipment requires skilled laborers in multiple disciplines such as equipment operators, mechanics, electricians and engineers, 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. If coal


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prices decrease in the future or our labor 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 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, subject to certain voting and other procedural requirements. 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 through potential strikes, slowdowns, picketing and work stoppages, and materially reduce our profitability.
 
Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.
 
Our ability to receive payment for the coal we sell depends on the continued creditworthiness of our customers. The current economic volatility and tightening credit markets increase the risk that we may not be able to collect payments from our customers. A continuation or worsening of current economic conditions or other prolonged global or U.S. recessions could also impact the creditworthiness of our customers. If the creditworthiness of a customer declines, this would increase the risk that we may not be able to collect payment for all of the coal we sell to that customer. If we determine that a customer is not creditworthy, 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 the customer’s coal on the spot market, which may be at prices lower than the contract price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could have a material adverse effect on our financial position. 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.
 
We will be required by Section 404 of the Sarbanes-Oxley Act to evaluate the effectiveness of our internal controls. We have identified control deficiencies, including material weaknesses, in the past, which have been remediated. If we are unable to establish and maintain effective internal controls, our financial condition and operating results could be adversely affected.
 
We are in the process of evaluating our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We are also in the process of performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002. We anticipate that we will be required to comply with Section 404 for the year ending December 31, 2013.
 
However, we cannot be certain as to the timing of completion of our evaluation, testing and remediation actions or the impact of the same on our operations. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board rules and regulations that remain unremediated. As a public company, we will be required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that, or that are reasonably likely to, materially affect internal controls over financial reporting. A “material weakness” is a deficiency or combination of deficiencies in internal controls over financial reports that results in more than a remote likelihood that a material misstatement of the annual or interim consolidated financial statements will not be prevented or detected. A “significant deficiency” is a deficiency or combination of deficiencies that is less severe than a material weakness.
 
We have identified deficiencies in our internal control over financial reporting, including in connection with the financial statement close process for the year ended December 31, 2011, in which we identified an error in our calculation of depreciation, depletion, and amortization. Although we believe this material weakness has been remediated, if we are unable to appropriately maintain the remediation plan we have


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implemented and maintain any other necessary controls we implement in the future, our management might not be able to certify, and our independent registered public accounting firm might not be able to deliver an unqualified report on the adequacy of our internal control over financial reporting.
 
If we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC. In addition, failure to comply with Section 404 or the report by us of a material weakness may cause investors to lose confidence in our consolidated financial statements, and as a result our common stock price may be adversely affected. If we fail to remedy any material weakness, our consolidated financial statements may be inaccurate, we may face restricted access to the capital markets and our common stock price may be adversely affected.
 
Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war could have a material adverse effect on our business, financial condition or 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 United States 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 United States. 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, financial condition and results of operations.
 
Risks Related to Environmental, Other Regulations and Legislation
 
New regulatory requirements limiting greenhouse gas emissions could adversely affect coal-fired power generation and reduce the demand for coal as a fuel source, which could cause the price and quantity of the coal we sell to decline materially.
 
One major by-product of burning coal is carbon dioxide (“CO2”), which is a greenhouse gas and a source of concern with respect to global warming, also known as Climate Change. Climate Change continues to attract government, public and scientific attention, especially on ways to reduce greenhouse gas emissions, including from coal-fired power plants. Various international, federal, regional and state proposals are being considered to limit emissions of greenhouse gases, including possible future U.S. treaty commitments, new federal or state legislation that may establish a cap-and-trade regime, and regulation under existing environmental laws by the EPA and other regulatory agencies. Future regulation of greenhouse gas emissions may require additional controls on, or the closure of, coal-fired power plants and industrial boilers and may restrict the construction of new coal-fired power plants.
 
The permitting of new coal-fired power plants has also recently been contested by state regulators and environmental advocacy organizations due to concerns related to greenhouse gas emissions. In addition, a federal appeals court has allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of carbon dioxide, although the U.S. Supreme Court has since held that federal common law provides no basis for such claims. Future regulation, litigation and permitting related to greenhouse gas emissions may cause some users of coal to switch from coal to a lower-carbon fuel, or otherwise reduce the use of and demand for fossil fuels, particularly coal, which could have a material adverse effect on our business, financial condition or results of operations. See “Business — Regulation and Laws — Climate Change.”
 
Extensive environmental requirements, including existing and potential future 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.
 
Coal contains impurities, including but not limited to sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. The operations of our customers are


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subject to extensive environmental requirements, 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 (“SO2”), particulate matter, nitrogen oxides (“NOx”), 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, SO2, NOx, toxic gases and other air pollutants have been proposed or could become effective in coming years. In addition, 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. The content of additional requirements in the U.S. is in the process of being developed, and many new initiatives remain subject to review by federal or state agencies or the courts. Stringent air emissions limitations are either in place or may 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 and the construction of new coal-fired power plants may become less desirable. The EIA’s expectations for the coal industry assume there will be a significant number of as yet unplanned coal-fired plants built in the future. Any switching of fuel sources away from coal, closure of existing coal-fired plants, or reduced construction of new plants could have a material adverse effect on demand for and prices received for our coal.
 
In addition, contamination caused by the disposal of coal combustion byproducts, including coal ash, can lead to material liability to our customers under federal and state laws. In addition, the EPA has proposed a rule concerning management of coal combustion residuals. New EPA regulation of such management would likely increase the ultimate costs to our customers of coal combustion. Such liabilities and increased costs in turn could have a material adverse effect on the demand for and prices received for our coal.
 
See “Business — Regulation and Laws” for more information about the various governmental regulations affecting us.
 
Legal requirements that we expect to significantly expand scrubbed coal-fired electricity generating capacity may be overturned or not enacted at all, which could result in less demand for Illinois Basin coal than we anticipate and materially and adversely affect our coal prices and/or sales.
 
Although a number of legal requirements have been or are in the process of being implemented that are expected to expand significantly the scrubbed coal-fired electricity generating capacity in the U.S., regulations driving this trend are subject to legal challenge, and could also be the subject of future legislation that withdraws any authorization for such requirements. For example, the recently finalized Cross-State Air Pollution Rule (“CSAPR”) has been challenged in court by a number of southern and Midwestern states and several energy companies. In December 2011, the U.S. Court of Appeals for the District of Columbia Circuit issued a ruling to stay the CSAPR pending judicial review. The outcome of such legal proceedings, and other possible developments including, for example, changes in presidential administration and the administration of the EPA, or the enactment by Congress of more lenient air pollution laws than are currently in effect, could result in significantly less expansion of scrubbed coal-fired electricity generating capacity than we anticipate. This in turn could mean that the strong increase in demand for relatively high-sulfur Illinois Basin coal we believe will occur in the future may not materialize, or may not materialize as soon as it otherwise would. This could adversely affect the demand for our coal and the price we will receive, which could materially and adversely affect our coal prices and/or sales.
 
Our failure to obtain and renew permits and approvals necessary for our mining operations could negatively affect our business.
 
Coal production is dependent on our ability to obtain and maintain various federal and state permits and approvals to mine our coal reserves within the timeline specified in our mining plans. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, which may increase the costs or possibly preclude the continuance of ongoing mining operations or the development of future mining operations. In addition, the public, including


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non-governmental organizations, anti-mining groups and individuals, have certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. The slowing pace at which necessary permits are issued or renewed for new and existing mines has materially impacted coal production, especially in Central Appalachia. Permitting by the Army Corps of Engineers (the “Corps”), the EPA and the Department of the Interior has become subject to “enhanced review” under both the Surface Mining Control and Reclamation Act of 1977 (the “SMCRA”), and the federal Clean Water Act (the “CWA”), to reduce the harmful environmental consequences of mountain-top mining, especially in the Appalachian region.
 
For example, in April 2010, the EPA issued comprehensive interim final guidance regarding the review of certain new and renewed CWA permit applications for Appalachian surface coal mining operations. EPA’s guidance is subject to several pending legal challenges related to its legal effect and sufficiency including consolidated challenges pending in Federal District Court in the District of Columbia led by the National Mining Association. This guidance may apply to our applications to obtain and maintain permits that are important to our operations. We cannot give any assurance regarding the impact that this or any successor guidance may have on the issuance or renewal of such permits.
 
Typically, we submit the necessary permit applications 12 to 30 months before we plan to mine a new area. Some of our required mining permits are becoming increasingly difficult to obtain within the time frames to which we were previously accustomed, and in some instances we have had to delay the mining of coal in certain areas covered by the application in order to obtain required permits and approvals. Permits could be delayed in the future if the EPA continues its enhanced review of CWA applications. If the required permits are not issued or renewed in a timely fashion or at all, or if permits 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 operations, and there could be a material adverse effect on our ability to produce coal profitably. See “Business — Regulation and Laws.”
 
Section 404(q) of the CWA establishes a requirement that the Secretary of the Army and the Administrator of the EPA enter into an agreement assuring that delays in the issuance of permits under Section 404 are minimized. In August 1992, the Department of the Army and the EPA entered into such an agreement. The 1992 Section 404(q) Memorandum of Agreement (“MOA”) outlines the current process and time frames for resolving disputes in an effort to issue timely permit decisions. Under this MOA, the EPA may request that certain permit applications receive a higher level of review within the Department of Army. In these cases, the EPA determines that issuance of the permit will result in unacceptable adverse effects to Aquatic Resources of National Importance (“ARNI”). Alternately, the EPA may raise concerns over Section 404 program policies and procedures. An ARNI is a resource-based threshold used to determine whether a dispute between the EPA and the Corps regarding individual permit cases are eligible for elevation under the MOA. Factors used in identifying ARNIs include the economic importance of the aquatic resource, rarity or uniqueness, and/or importance of the aquatic resource to the protection, maintenance, or enhancement of the quality of the waters.
 
We received notice from the EPA dated July 25, 2011 that it believes that the proposed discharge plan submitted by us in connection with our Section 404 permit application for the expanded mining at our Midway Mine would result in unacceptable impacts on ARNIs, and in particular, downstream waters outside the scope of the permit area. As a result, it is possible that the Corps will deny our pending permit application, or that the EPA will elevate the permit application to a higher level of review should the Corps proceed with the issuance of the permit notwithstanding EPA’s concerns. Ultimately, the EPA may consider initiating a Section 404(c) “veto” of the permit. A material delay in the issuance of this permit, or other Section 404 permits that we may require as part of our mining operations, or the denial or veto of such permits, could have a materially negative effect on our operations and profitability.


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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 were to occur, capital expenditures could be required in order for us to be allowed could be required in order for us to be allowed to reopen the mine. In the event that these agencies order the closing of our mines, our coal sales contracts generally allow 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 reopen 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.
 
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;
 
  •  the effects of mining on surface water and groundwater quality and availability; and
 
  •  the management of electrical equipment containing polychlorinated biphenyls.
 
The costs, liabilities and requirements associated with the laws and regulations related to these and other environmental matters may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. We cannot assure you that we have been or will be at all times in compliance with the applicable 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, we 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


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further regulate and tax the coal industry, may also require us to change operations significantly or incur increased costs. For example, in December 2008, the U.S. Department of the Interior’s Office of Surface Mining Reclamation and Enforcement (the “OSM”) revised the original “stream buffer zone” rule (the “SBZ Rule”), which had been issued under the SMCRA in 1983. The SBZ Rule was challenged in the U.S. District Court for the District of Columbia. In a March 2010 settlement with the litigation parties, the OSM agreed to use its best efforts to adopt a final rule by June 2012. In addition, Congress has proposed, and may in the future propose, legislation to restrict the placement of mining material in streams. The requirements of the revised SBZ Rule or future legislation, when adopted, will likely be stricter than the prior SBZ Rule to further protect streams from the impact of surface mining. Such changes could have a material adverse effect on our financial condition and results of operations. See “Business — Regulation and Laws.”
 
If the assumptions underlying our estimates of reclamation and mine closure obligations are inaccurate, our costs could be greater than anticipated.
 
SMCRA and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of underground mining. We base our estimates of reclamation and mine closure liabilities on permit requirements, engineering studies and our engineering expertise related to these requirements. Our management and engineers periodically review these estimates. The estimates can change significantly if actual costs vary from our original assumptions or if governmental regulations change significantly. We are required to record new obligations as liabilities at fair value under generally accepted accounting principles. In estimating fair value, we considered the estimated current costs of reclamation and mine closure and applied inflation rates and a third-party profit, as required. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on our behalf. The resulting estimated reclamation and mine closure obligations could change significantly if actual amounts change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial condition.
 
Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.
 
Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time, which may affect runoff or drainage water or other aspects of the environment. We could become subject to claims 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. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share.
 
We maintain extensive coal refuse areas and slurry impoundments at a number of our mines. Such areas and impoundments are subject to extensive regulation. Slurry impoundments have been known to fail, releasing large volumes of coal slurry into the surrounding environment. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which could pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for civil or criminal fines and penalties.
 
Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage,” which we refer to as AMD. The treating of AMD can be costly. Although we do not currently face material costs associated with AMD, it is possible that we could incur significant costs in the future.


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These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could materially and adversely affect us.
 
Changes in the legal and regulatory environment could complicate or limit our business activities, increase our operating costs or result in litigation.
 
The conduct of our businesses is subject to various laws and regulations administered by federal, state and local governmental agencies in the United States. These laws and regulations may change, sometimes dramatically, as a result of political, economic or social events or in response to significant events. Certain recent developments particularly may cause changes in the legal and regulatory environment in which we operate and may impact our results or increase our costs or liabilities. Such legal and regulatory environment changes may include changes in:
 
  •  the processes for obtaining or renewing permits;
 
  •  costs associated with providing healthcare benefits to employees;
 
  •  health and safety standards;
 
  •  accounting standards;
 
  •  taxation requirements; and
 
  •  competition laws.
 
In 2006, the Federal Mine Improvement and New Emergency Response Act of 2006 (the “MINER Act”), was enacted. The MINER Act significantly amended the Federal Mine Safety and Health Act of 1977 (the “Mine Act”), imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities.
 
Following the passage of the MINER Act, the U.S. Mine Safety and Health Administration (“MSHA”), issued new or more stringent rules and policies on a variety of topics, including:
 
  •  sealing off abandoned areas of underground coal mines;
 
  •  mine safety equipment, training and emergency reporting requirements;
 
  •  substantially increased civil penalties for regulatory violations;
 
  •  training and availability of mine rescue teams;
 
  •  underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;
 
  •  flame-resistant conveyor belt, fire prevention and detection, and use of air from the belt entry; and
 
  •  post-accident two-way communications and electronic tracking systems.
 
Subsequent to passage of the MINER Act, Illinois, Kentucky, Pennsylvania, Ohio and West Virginia have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Other states may pass similar legislation in the future. Also, additional federal and state legislation that further increase mine safety regulation, inspection and enforcement, particularly with respect to underground mining operations, has been considered in light of recent fatal mine accidents. In 2010, the 111th Congress introduced federal legislation seeking to impose extensive additional safety and health requirements on coal mining. While the legislation was passed by the House of Representatives, the legislation was not voted on in the Senate and did not become law. On January 26, 2011, the same legislation was reintroduced in the 112th Congress by Senators Jay Rockefeller (D-W.Va.), Tom Harkin (D-Iowa), Patty Murray (D-Wash.) and Joe Manchin III (D-W.Va.). Further workplace accidents are likely to also result in more stringent enforcement and possibly the passage of new laws and regulations.


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The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), that was signed into law on July 21, 2010, requires public companies to disclose in their periodic reports filed with the Securities and Exchange Commission (the “SEC”) substantial additional information about safety issues relating to our mining operations. After effectiveness of our registration statement, we will be subject to the provisions of the Dodd-Frank Act.
 
In response to the April 2010 explosion at Massey Energy Company’s Upper Big Branch Mine and the ensuing tragedy, we expect that safety matters pertaining to underground coal mining operations may be the topic of additional new federal and/or state legislation and regulation, as well as the subject of heightened enforcement efforts. For example, federal authorities have announced special inspections of coal mines to evaluate several safety concerns, including the accumulation of coal dust and the proper ventilation of gases such as methane. In addition, federal authorities have announced that they are considering changes to mine safety rules and regulations which could potentially result in additional or enhanced required safety equipment, more frequent mine inspections, stricter and more thorough enforcement practices and enhanced reporting requirements. Any new environmental, health and safety requirements may be replicated in the states in which we operate and could increase our operating costs or otherwise may prevent, delay or reduce our planned production, any of which could adversely affect our financial condition, results of operations and cash flows.
 
Although we are unable to quantify the full impact, implementing and complying with new laws and regulations could have an adverse impact on our business and results of operations and could result in harsher sanctions in the event of any violations. See “Business — Regulation and Laws.”
 
Certain United States federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of future legislation.
 
President Obama’s Proposed Fiscal Year 2012 budget recommends elimination of certain key United States federal income tax preferences relating to coal exploration and development (the “Budget Proposal”). The Budget Proposal would (1) eliminate current deductions and 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, (2) repeal the percentage depletion allowance with respect to coal properties, (3) repeal capital gains treatment of coal and lignite royalties, and (4) exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange, or other disposition of coal, other hard mineral fossil fuels, or primary products thereof. The passage of any legislation as a result of the Budget Proposal or any other similar changes in United States federal income tax laws could eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase our taxable income and negatively impact the value of an investment in our common stock.
 
Risks Related to This Offering and Our Common Stock
 
An active, liquid trading market for our common stock may not develop.
 
Prior to this offering, there has not been a public market for our common stock. We cannot predict the extent to which investor interest in us will lead to the development of a trading market on Nasdaq or otherwise or how active and liquid that market may become. If an active and liquid trading market does not develop, you may have difficulty selling any of our common stock that you purchase.
 
Our stock price may change significantly following the offering, and you could lose all or part of your investment as a result.
 
Even if an active trading market develops, the market price for shares of our common stock may be highly volatile and could be subject to wide fluctuations after this offering. We and the underwriters will negotiate to determine the initial public offering price. You may not be able to resell your shares at or above


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the initial public offering price due to a number of factors such as those listed in “— Risks Related to the Company.” Some of the factors that could negatively affect our share price include:
 
  •  changes in oil and gas prices;
 
  •  changes in our funds from operations and earnings estimates;
 
  •  publication of research reports about us or the energy services industry;
 
  •  increase in market interest rates, which may increase our cost of capital;
 
  •  changes in applicable laws or regulations, court rulings and enforcement and legal actions;
 
  •  changes in market valuations of similar companies;
 
  •  adverse market reaction to any increased indebtedness we may incur in the future;
 
  •  additions or departures of key management personnel;
 
  •  actions by our stockholders;
 
  •  speculation in the press or investment community;
 
  •  a large volume of sellers of our common stock pursuant to our resale registration statement with a relatively small volume of purchasers; or
 
  •  general market and economic conditions.
 
Furthermore, the stock market has recently experienced extreme volatility that in some cases has been unrelated or disproportionate to the operating performance of particular companies. These broad market and industry fluctuations may adversely affect the market price of our common stock, regardless of our actual operating performance.
 
In the past, following periods of market volatility, stockholders have instituted securities class action litigation. If we were involved in securities litigation, it could have a substantial cost and divert resources and the attention of executive management from our business regardless of the outcome of such litigation.
 
The offering price per share of the common stock may not accurately reflect its actual value.
 
The initial public offering price per share of our common stock offered under this prospectus reflects the result of negotiations between us and the underwriters. The offering price may not accurately reflect the value of our common stock, and may not be indicative of prices that will prevail in the open market following this offering.
 
We do not anticipate paying any dividends on our common stock in the foreseeable future.
 
For the foreseeable future, we intend to retain earnings to grow our business. Payments of future dividends, if any, will be at the discretion of our board of directors and will depend on many factors, including general economic and business conditions, our strategic plans, our financial results and condition, legal requirements and other factors as our board of directors deems relevant. Our Senior Secured Credit Facility restricts our ability to pay cash dividends on our common stock and we may also enter into credit agreements or borrowing arrangements in the future that will restrict our ability to declare or pay cash dividends on our common stock.
 
We will incur increased costs as a result of being a public company.
 
As a privately held company, we have not been responsible for the corporate governance and financial reporting practices and policies required of a publicly traded company. Following the effectiveness of the registration statement of which this prospectus is a part, we will be a public company. As a public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the


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requirements of Nasdaq or other stock exchange on which our common stock is listed, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:
 
  •  institute a more comprehensive compliance function;
 
  •  design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;
 
  •  comply with rules promulgated by the NYSE, Nasdaq or other stock exchange on which our common stock is listed;
 
  •  prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
 
  •  establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;
 
  •  involve and retain to a greater degree outside counsel and accountants in the above activities; and
 
  •  establish an investor relations function.
 
In addition, we also expect that being a public company subject to these rules and regulations will require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.
 
Future sales, or the perception of future sales, of our common stock may depress our share price.
 
We may in the future issue our previously authorized and unissued securities. At the closing of this offering, we will be authorized to issue      shares of common stock and preferred stock with such designations, preferences and rights as determined by our board of directors. The potential issuance of such additional shares of common stock will result in the dilution of the ownership interests of the purchasers of our common stock in this offering and may create downward pressure on the trading price, if any, of our common stock. The sales of substantial amounts of our common stock following the effectiveness of the registration statement of which this prospectus is a part, or the perception that these sales may occur, could cause the market price of our common stock to decline and impair our ability to raise capital. Based on      shares of common stock outstanding as of     , 2012, upon completion of this offering, we will have      shares of common stock outstanding. Of these outstanding shares, all of the shares of our common stock sold in this offering will be freely tradable in the public market, except for any shares held by our affiliates, as defined in Rule 144 under the Securities Act of 1933, as amended (the “Securities Act”).
 
We, our directors, executive officers and stockholders have agreed with the underwriters, subject to certain exceptions, not to dispose of or hedge any shares of our common stock or any securities convertible into, or exercisable or exchangeable for, shares of our common stock for a period of 180 days from the date of this prospectus, which may be extended upon the occurrence of specified events, except with the prior written consent of     .     , at any time and without notice, may release all or any portion of the common stock subject to the lock-up agreements entered into in connection with this offering. If the restrictions under the lock-up agreements are waived, our common stock will be available for sale into the market, which could reduce the market value for our common stock.
 
After the expiration of the lock-up agreements and other contractual restrictions that prohibit transfers for at least 180 days after the date of this prospectus, up to      restricted securities may be sold into the public market in the future without registration under the Securities Act to the extent permitted under Rule 144. Of these restricted securities, approximately      shares will be available for sale approximately      days after the date of this prospectus, subject to volume or other limits under Rule 144.


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If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock, or if our operating results do not meet their expectations, the price and trading volume of our common stock could decline.
 
The trading market for our common stock will be influenced by the research and reports that securities or industry analysts publish about us or our business. Securities analysts may elect not to provide research coverage of our common stock. This lack of research coverage could adversely affect the price of our common stock. We do not have any control over these reports or analysts. If any of the analysts who cover us downgrades our stock, or if our operating results do not meet the analysts’ expectations, our stock price could decline. Moreover, if any of these analysts ceases coverage of us or fails to publish regular reports on our business, we could lose visibility in the market, which in turn could cause our common stock price and trading volume to decline and our common stock to be less liquid.
 
You will incur immediate dilution in the book value of your common stock as a result of this offering.
 
The initial public offering price of our common stock is considerably more than the as adjusted, net tangible book value per share of our outstanding common stock. This reduction in the value of your equity is known as dilution. This dilution occurs in large part because our earlier investors paid substantially less than the initial public offering price when they purchased their shares. Investors purchasing common stock in this offering will incur immediate dilution of $      in as adjusted, net tangible book value per share of common stock, based on the assumed initial public offering price of $      per share, which is the midpoint of the price range listed on the front cover page of this prospectus. In addition, following this offering, purchasers in the offering will have contributed     % of the total consideration paid by our stockholders to purchase shares of common stock. For a further description of the dilution that you will experience immediately after this offering, see “Dilution.” In addition, if we raise funds by issuing additional securities, the newly-issued shares will further dilute your percentage ownership of us.
 
Provisions in our organizational documents and under Delaware law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.
 
The existence of some provisions in our organizational documents and under Delaware law could delay or prevent a change in control of our company that a stockholder may consider favorable, which could adversely affect the price of our common stock. The provisions in our amended and restated certificate of incorporation and bylaws that could delay or prevent an unsolicited change in control of our company include board authority to issue preferred stock without stockholder approval, and advance notice provisions for director nominations or business to be considered at a stockholder meeting. These provisions may also discourage acquisition proposals or delay or prevent a change of control, which could harm our stock price. See “Description of Capital Stock — Anti-Takeover Effects of Certain Provisions of Our Amended and Restated Certificate of Incorporation, Bylaws and Delaware Law.”
 
Our management team may not be able to organize and effectively manage a publicly traded operating company, which could adversely affect our overall financial position.
 
Some of our senior executive officers or directors have not previously organized or managed a publicly traded operating company, and our senior executive officers and directors may not be successful in doing so. The demands of organizing and managing a publicly traded operating company are much greater as compared to a private company and some of our senior executive officers and directors may not be able to meet those increased demands. Failure to organize and effectively manage us could adversely affect our overall financial position.


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Future offerings of debt securities, which would rank senior to our common stock upon our liquidation, and future offerings of equity securities, which would dilute our existing stockholders, may adversely affect the market value of common stock.
 
In the future, we may attempt to increase our capital resources by making offerings of debt or additional offerings of equity securities, including commercial paper, medium-term notes, senior or subordinated notes and classes of preferred stock. Upon liquidation, holders of our debt securities and preferred stock and lenders with respect to other borrowings will receive a distribution of our available assets prior to the holders of our common stock. Additional equity offerings may dilute the holdings of our existing stockholders or reduce the market value of our common stock, or both. Our preferred stock, which could be issued without stockholder approval, if issued, could have a preference on liquidating distributions or a preference on dividend payments that would limit amounts available for distribution to holders of our common stock. Because our decision to issue securities in any future offering will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing or nature of our future offerings. Thus, holders of our common stock bear the risk of our future offerings reducing the market value of our common stock and diluting their share holdings in us.
 
Non-U.S. holders of our common stock may be subject to United States federal income tax with respect to gain on the disposition of our common stock.
 
If we are or have been a “United States real property holding corporation” within the meaning of the Internal Revenue Code of 1986, as amended (the “Code”), at any time within the shorter of (1) the five-year period preceding a disposition of our common stock by a non-U.S. holder (as defined below under “Material United States Federal Income and Estate Tax Consequences to Non-U.S. Holders”), or (2) such holder’s holding period for such common stock, and assuming our common stock is “regularly traded,” as defined by applicable United States Treasury regulations, on an established securities market, the non-U.S. holder may be subject to United States federal income tax with respect to gain on such disposition if it held more than 5% of our common stock at any time during the shorter of periods (1) and (2) above. We believe we are, and will continue to be, a United States real property holding corporation.
 
If our common stock is not considered to be regularly traded on an established securities market during the calendar year in which a sale or disposition occurs, the buyer or other transferee of our common stock generally will be required to withhold tax at the rate of 10% on the sales price or other amount realized as a prepayment of a transferor’s United States federal income tax liability, unless the transferor furnishes an affidavit certifying that it is not a foreign person in the manner and form specified in applicable United States Treasury regulations.


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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
 
Various statements contained in this prospectus, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. These forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. The forward-looking statements in this prospectus speak only as of the date of this prospectus; we disclaim any obligation to update these statements unless required by law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These and other important factors, including those discussed under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. These risks, contingencies and uncertainties include, but are not limited to, the following:
 
  •  market demand for coal and electricity;
 
  •  geologic conditions, weather and other inherent risks of coal mining that are beyond our control;
 
  •  competition within our industry and with producers of competing energy sources;
 
  •  excess production and production capacity;
 
  •  our ability to acquire or develop coal reserves in an economically feasible manner;
 
  •  inaccuracies in our estimates of our coal reserves;
 
  •  availability and price of mining and other industrial supplies, including steel-based supplies, diesel fuel, rubber tires and explosives;
 
  •  availability of skilled employees and other workforce factors;
 
  •  disruptions in the quantities of coal produced at our operations as a consequence of weather or equipment or mine failures;
 
  •  our ability to collect payments from our customers;
 
  •  defects in title or the loss of a leasehold interest;
 
  •  railroad, barge, truck and other transportation performance and costs;
 
  •  our ability to secure new coal supply arrangements or to renew existing coal supply arrangements;
 
  •  our relationships with, and other conditions affecting, our customers;
 
  •  the deferral of contracted shipments of coal by our customers;
 
  •  our ability to service our outstanding indebtedness;
 
  •  our ability to comply with the restrictions imposed by our Senior Secured Credit Facility and other financing arrangements;
 
  •  the availability and cost of surety bonds;
 
  •  terrorist attacks, military action or war;
 
  •  our ability to obtain and renew various permits, including permits authorizing the disposition of certain mining waste;


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  •  existing and future legislation and regulations affecting both our coal mining operations and our customers’ coal usage, governmental policies and taxes, including those aimed at reducing emissions of elements such as mercury, sulfur dioxide, nitrogen oxides, toxic gases, such as hydrogen chloride, particulate matter or greenhouse gases;
 
  •  the accuracy of our estimates of reclamation and other mine closure obligations;
 
  •  customers’ ability to meet existing or new regulatory requirements and associated costs, including disposal of coal combustion waste material;
 
  •  our ability to attract/retain key management personnel;
 
  •  efforts to organize our workforce for representation under a collective bargaining agreement;
 
  •  costs to comply with the Sarbanes-Oxley Act of 2002; and
 
  •  the other factors affecting our business described below under the caption “Risk Factors.”


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USE OF PROCEEDS
 
We estimate that the net proceeds to us from the sale of our common stock in this offering will be $      million, at an assumed initial public offering price of $      per share, the midpoint of the price range set forth on the cover of this prospectus, and after deducting estimated underwriting discounts and commissions and offering expenses estimated at $      million. Our net proceeds will increase by approximately $      million if the underwriters’ option to purchase additional shares is exercised in full. Each $1.00 increase (decrease) in the assumed initial public offering price of $      per share, the midpoint of the price range set forth on the cover of this prospectus, would increase (decrease) the net proceeds to us of this offering by $      million, or $      million if the underwriters’ option is exercised in full, assuming the number of shares offered by us, as set forth on the cover of this prospectus, remains the same and after deducting estimated underwriting discounts and commissions and offering expenses.
 
We intend to use $      million of the net proceeds from this offering to repay a portion of our outstanding borrowings under our Senior Secured Term Loan, $      million of the net proceeds to repay a portion of our outstanding borrowings under our Senior Secured Revolving Credit Facility and the balance, if any, for general corporate purposes, including to fund capital expenditures relating to our mining operations and working capital. The interest rate applicable to the Senior Secured Term Loan and the Senior Secured Revolving Credit Facility fluctuates based on our leverage ratio and the applicable interest option elected. The interest rate as of December 31, 2011 was 5.25%. The Senior Secured Credit Facility matures on February 9, 2016. See “Description of Indebtedness.” Raymond James Bank, FSB, an affiliate of Raymond James & Associates, Inc. is a lender under our Senior Secured Term Loan and our Senior Secured Revolving Credit Facility and may receive a portion of the net proceeds of this offering. See “Conflicts of Interest.”


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DIVIDEND POLICY
 
Historically, we have not paid cash dividends to holders of our common stock. For the foreseeable future, we intend to retain earnings to grow our business. Payments of future dividends, if any, will be at the discretion of our board of directors and will depend on many factors, including general economic and business conditions, our strategic plans, our financial results and condition, legal requirements and other factors that our board of directors deems relevant. Our Senior Secured Credit Facility restricts our ability to pay cash dividends on our common stock, and we may also enter into credit agreements or other borrowing arrangements in the future that will restrict our ability to declare or pay cash dividends on our common stock.


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CAPITALIZATION
 
The following table shows:
 
  •  Our capitalization as of December 31, 2011; and
 
  •  Our unaudited pro forma capitalization as of December 31, 2011, as adjusted, to reflect the following: (a) the receipt of the net proceeds from the sale by us in this offering of shares of common stock at an assumed public offering price of $      per share, the midpoint of the range set forth on the front cover page of this prospectus, after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us, (b) the repayment of certain outstanding indebtedness with the application of proceeds from this offering, and (c) the application of amounts we expect to receive from the Concurrent ARP Offering and related transactions as described in “Certain Relationships and Related Party Transactions — Concurrent Transactions with Armstrong Resource Partners.”
 
We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical and unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Selected Historical Consolidated Financial and Operating Data,” “Unaudited Pro Forma Financial Information,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
                 
    As of December 31, 2011  
          Pro-Forma As
 
    Actual     Adjusted(1)(2)  
    (In thousands)  
 
Cash and cash equivalents
  $ 19,580     $        
                 
Long-term debt, including current portion(3):
               
Revolving credit facility
  $ 40,000     $    
Term loan facility
    100,000          
Capital leases
    14,054          
Other
    19,709          
                 
Total long-term debt
    173,763          
Stockholders’ equity:
               
Common stock, $0.01 par value; 70,000,000 shares authorized and 19,110,500 shares issued and outstanding on an actual basis; 70,000,000 shares authorized and           shares issued and outstanding on an as adjusted basis(4)
    191          
Additional paid-in-capital
    208,044          
Accumulated deficit
    (38,250 )        
Accumulated other comprehensive income
    (1,862 )        
Non-controlling interest
    15          
                 
Total stockholders’ equity
    168,138          
                 
Total capitalization
  $ 341,901     $  
                 
 
 
(1) Each $1.00 increase or decrease in the assumed public offering price of $      per share would increase or decrease, respectively, each of total stockholders’ equity and total capitalization by approximately $      million, after deducting the underwriting discount and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. Each increase of 1.0 million shares offered by us, together with a concomitant $1.00 increase in the assumed offering price to $      per share, would increase total stockholders’ equity and total capitalization by approximately $      million. Similarly, each decrease of 1.0 million shares offered by us, together with a concomitant $1.00 decrease in the assumed offering price to $      per share, would decrease total stockholders’ equity and total capitalization by approximately $      million. The information discussed above is illustrative only


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and will be adjusted based on the actual public offering price and other terms of this offering determined at pricing.
 
(2) Each $1.00 increase or decrease in the assumed public offering price of the Concurrent ARP Offering of $      per share if paid to us as described in “Certain Relationships and Related Party Transactions — Concurrent Transactions with Armstrong Resource Partners” would increase or decrease, respectively, each of total stockholders’ equity and total capitalization by approximately $      million, after deducting the underwriting discount and estimated offering expenses payable by Armstrong Resource Partners. Armstrong Resource Partners may also increase or decrease the number of shares it is offering. Each increase of 1.0 million shares offered by Armstrong Resource Partners, together with a concomitant $1.00 increase in the assumed offering price of the Concurrent ARP Offering to $      per share, if paid to us, would increase total stockholders’ equity and total capitalization by approximately $      million. Similarly, each decrease of 1.0 million shares offered by Armstrong Resource Partners, together with a concomitant $1.00 decrease in the assumed offering price of the Concurrent ARP Offering to $      per share, if paid to us, would decrease total stockholders’ equity and total capitalization by approximately $      million. The information discussed above is illustrative only and will be adjusted based on the actual public offering price and other terms of this offering determined at pricing.
 
(3) Total debt does not include $71.0 million of certain long-term obligations to Armstrong Resource Partners that are characterized as financing transactions due to our continuing involvement in the lease of the related land and mineral reserves.
 
(4) The number of shares of common stock issued and outstanding on a pro forma basis includes shares of common stock outstanding, including awards of unrestricted stock to management, excludes awards of unvested restricted stock to management, and does not reflect the repurchase of      shares of common stock in connection with the cancellation of certain indebtedness. See “Certain Relationships and Related Party Transactions — Loans to Executive Officers and Loan Repayment” for additional information.


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DILUTION
 
Dilution is the amount by which the offering price paid by purchasers of common stock sold in this offering will exceed the pro forma net tangible book value per share of common stock after the offering. As of December 31, 2011, our net tangible book value was approximately $     , or $      per share. Net tangible book value is our total tangible assets less total liabilities. Based on an assumed initial offering price of $      per share of common stock, on a pro forma as adjusted basis as of     , after giving effect to the offering of      shares of common stock and the application of the related net proceeds, our net tangible book value was $      million, or $      per share of common stock. Purchasers of common stock in this offering will experience immediate and substantial dilution in net tangible book value per share for financial accounting purposes, as illustrated in the following table:
 
                 
Assumed purchase price per share of common stock
              $        
Net tangible book value per share before this offering
               
Decrease in net tangible book value per share attributable to new investors
               
Less: Pro forma net tangible book value per share after this offering
               
Immediate dilution in net tangible book value per share to new investors
          $  
 
A $1.00 increase in the assumed initial public offering price of $      per share (which is the midpoint of the range set forth in the cover of this prospectus) would increase our net tangible book value after the offering by $      million, and decrease the dilution to new investors by $     , assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.
 
The following table sets forth, as of     , 2012, the number of shares of common stock purchased from us, the total consideration paid to us and the average price per share paid by existing stockholders and to be paid by new investors purchasing shares of common stock in this offering, after giving pro forma effect to the Deconsolidation and to the new investors in this offering at the assumed initial public offering price of $      per share, together with the total consideration paid and average price per share paid by each of these groups, before deducting underwriting discounts and commissions and estimated offering expenses.
 
                                         
                            Average
 
    Shares Purchased     Total Consideration     Price per
 
    Number     Percent     Amount     Percent     Share  
    (In thousands)  
 
Existing stockholders
                  %   $                   %   $        
New investors
            %             %        
Total
            %   $         %   $  
 
The foregoing tables do not give effect to:
 
(a) 109,150 shares of restricted stock outstanding held by our employees, including our executive officers; and
 
(b) additional shares of common stock available for future issuance under our stock option and incentive plans.
 
If the underwriters’ over-allotment option is exercised in full, the number of shares held by new investors will be     , or approximately,     % of the total number of shares of common stock.


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UNAUDITED PRO FORMA FINANCIAL INFORMATION
 
The following tables present our selected unaudited pro forma consolidated financial and operating data for the periods indicated for Armstrong Energy. The following unaudited pro forma consolidated financial data of Armstrong Energy at December 31, 2011 and for the year ended December 31, 2011, are based on the historical consolidated financial statements of our Predecessor, which are included elsewhere in this prospectus.
 
The unaudited pro forma consolidated balance sheet data at December 31, 2011 gives effect to (a) the issuance of common stock in this offering and the application of the net proceeds therefrom as described in “Use of Proceeds,” and (b) the contribution of net proceeds to Armstrong Energy from the Concurrent ARP Offering, as if each had occurred on December 31, 2011.
 
The unaudited pro forma consolidated financial data for the fiscal year ended December 31, 2011 gives effect to (a) adjustments to interest expense as a result of the repayment of a portion of the secured promissory notes from the proceeds of this offering and (b) net adjustments to interest expense as a result of the repayment of a portion of the secured promissory notes from the proceeds contributed from the Concurrent ARP Offering, partially offset by additional interest expense associated with an additional long-term obligation owed to Armstrong Resource Partners, as if each had occurred on January 1, 2011.
 
This unaudited pro forma consolidated financial information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes included elsewhere in this prospectus.
 
Our unaudited pro forma adjustments are based on available information and certain assumptions that we believe are reasonable. Presentation of our unaudited pro forma consolidated financial and operating data is prepared in conformity with Article 11 of Regulation S-X. The unaudited pro forma consolidated financial and operating data is included for illustrative and informational purposes only and is not necessarily indicative of results we expect in future periods.


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Unaudited Pro Forma Consolidated Statement of Operations
For the Year Ended December 31, 2011
(In thousands, except per share data)
 
                                         
                      Pro Forma
    Pro Forma
 
                Pro Forma
    for the
    for this Offering,
 
                for this
    Concurrent
    and the
 
    As Reported
          Offering
    ARP Offering
    Concurrent ARP
 
    for the
          for the
    for the
    Offering for the
 
    Year Ended
    Adjustments
    Year Ended
    Year Ended
    Year Ended
 
    December 31,
    Related to this
    December 31,
    December 31,
    December 31,
 
    2011     Offering     2011     2011     2011  
 
Revenue
  $ 299,270     $           $           $           $        
Costs and expenses:
                                       
Operating costs and expenses
    221,597                                  
Depreciation, depletion, and amortization
    27,661                                  
Asset retirement obligation expense
    4,005                                  
Selling, general, and administrative costs
    38,072                                  
                                         
Operating income
    7,935                                  
Other income (expense):
                                       
Interest income
    145                                  
Interest expense
    (10,839 )     (A)             (B)        
Other income (expense), net
    (178 )                                
Gain on deconsolidation
    311                                  
Gain on extinguishment of debt
    6,954                                  
                                         
Income before income taxes
    4,328                                  
Income taxes
    (856 )                                
                                         
Net income
    3,472                                  
Income attributable to non-controlling interest
    (7,448 )                                
                                         
Net income attributable to common stockholders
  $ (3,976 )   $       $       $            
                                         
Pro forma earnings per share
                                       
Basic and diluted
                                  $    
                                         
Pro forma weighted average shares outstanding
                                       
Basic
                                       
                                         
Diluted
                                       
                                         
 
 
(A) Reflects elimination of historical interest expense related to secured promissory notes repaid with proceeds from this offering had it occurred on January 1, 2011.
 
(B) Reflects elimination of historical interest expense of $      million related to the secured promissory notes, as Armstrong Energy intends to utilize the net proceeds contributed from the Concurrent ARP Offering to repay these obligations. The amount is offset by additional interest expense of $      million associated with a long-term obligation Armstrong Energy would enter into with Armstrong Resource Partners in exchange for an undivided interest in additional mineral reserves.


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Unaudited Pro Forma Condensed Consolidated Balance Sheet
As of December 31, 2011
(Dollars in thousands)
 
                                         
                            Pro Forma for
 
                            this Offering
 
                            and the
 
                Pro Forma
    Adjustments
    Concurrent
 
                for this
    Related
    ARP Offering
 
    As Reported as
    Adjustments
    Offering as of
    to the
    as of
 
    of December 31,
    Related to this
    December 31,
    Concurrent
    December 31,
 
    2011     Offering     2011     ARP Offering     2011  
 
Assets
                                       
Current assets:
                                       
Cash and cash equivalents
  $ 19,580     $           $           $       (G)   $        
Accounts receivable
    22,506                                  
Inventories
    11,409                                  
Prepaid and other assets
    4,260                                  
                                         
Total current assets
    57,755                                  
Property, plant equipment, and mine development, net
    417,603                                
Investments
    3,178                                  
Intangible assets, net
    1,305                                  
Related party other receivables, net
                                     
Other noncurrent assets
    28,067       (C)                        
                                         
Total assets
  $ 507,908     $     $       $       $  
                                         
Liabilities and stockholders’ equity
                                       
Current liabilities:
                                       
Accounts payable
  $ 35,442     $       $       $       $    
Accrued liabilities and other
    14,638       (D)             (H),(I)        
Accrued interest on related party obligations
                                     
Current portion of capital lease obligations
    4,347                                  
Current maturities of long-term debt
    33,957                                  
                                         
Total current liabilities
    88,384                                  
Long-term debt, less current maturities
    125,752       (E)             (I)        
Long-term obligation to related party
    71,047                       (I)        
Related party payable
    25,700                                  
Asset retirement obligations
    17,131                                  
Long-term portion of capital lease obligations
    9,707                                  
Other non-current liabilities
    2,049                                  
                                         
Total liabilities
    339,770                                  
Stockholders’ equity:
                                       
Accumulated deficit
    (38,250 )     (C)                        
Accumulated other comprehensive income (loss)
    (1,862 )                                
Common stock
    191       (F)                        
Additional paid in capital
    208,044       (F)                        
                                         
Armstrong Energy, Inc.’s equity
    168,123                                  
Non-controlling interest
    15                                  
                                         
Total stockholders’ equity
    168,138                                  
                                         
Total liabilities and stockholders’ equity
  $ 507,908     $       $       $       $  
                                         
 
(C) Reflects the write-off of unamortized deferred financing costs associated with the expected repayment of a portion of the Senior Secured Term Loan with proceeds from the offering.
 
(D) Reflects the expected payment of accrued interest on $      million of the Senior Secured Term Loan and $      million of the Senior Secured Revolving Credit Facility repaid with proceeds from this offering.
 
(E) Reflects the expected repayment of $      million of the Senior Secured Term Loan and $      million of the Senior Secured Revolving Credit Facility with proceeds from this offering.


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(F) Reflects the adjustments to common stock and additional paid in capital for the public offering of Armstrong Energy’s common stock as follows (dollars in thousands):
 
         
Proceeds from this offering(1)
  $          
Less: estimated fees and expense related with this offering
       
         
Net proceeds from this offering
       
Less: par value of common stock issued in this offering(2)
       
         
Additional paid in capital on shares issued in this offering
  $  
         
 
 
  (1)  To reflect the issuance of        shares of Armstrong Energy’s common stock offered hereby at an assumed initial public offering price of $      per share (the mid point of the range set forth on the front cover page of this prospectus).
 
  (2)  To reflect the reclassification to common stock of the par value of $0.01 per share for the      shares issued in this offering.
 
(G) Reflects adjustments to cash and cash equivalents for sources and uses of funds from the Concurrent ARP Offering, summarized as follows (dollars in thousands):
 
         
Proceeds from the Concurrent ARP Offering(1), net of expenses
  $          
Use of cash to repay Senior Secured Revolving Credit Facility
       
Use of cash to pay accrued but unpaid interest
       
         
Pro forma adjustment
  $        
         
 
 
  (1)  To reflect the issuance of        common units of Armstrong Resource Partners representing limited partner interests to be offered by Armstrong Resource Partners pursuant to the concurrent ARP Offering at an assumed initial public offering price of $      per unit (the mid point of the range set forth on the front cover page of the prospectus related to the Concurrent ARP Offering).
 
(H) Reflects the expected payment of accrued interest on the portion of the Senior Secured Revolving Credit Facility repaid with proceeds contributed from the Concurrent ARP Offering.
 
(I) The expected net proceeds of the Concurrent ARP Offering of $      million will be paid to Armstrong Energy to purchase an undivided interest in additional mineral reserves of Armstrong Energy. The amount received is expected to be utilized to repay the remaining outstanding balance of the Senior Secured Revolving Credit Facility (approximately $      million) and related accrued interest (approximately $      million), with expected excess cash of approximately $      million. Armstrong Energy expects to simultaneously enter into a financing arrangement with Armstrong Resource Partners to mine the mineral reserves transferred, resulting in the recognition of an obligation of $      million.


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SELECTED HISTORICAL
CONSOLIDATED FINANCIAL
AND OPERATING DATA
 
The following table presents our selected historical consolidated financial and operating data for the periods indicated for Armstrong Energy, Inc.’s predecessor, Armstrong Land Company, LLC and its subsidiaries (our “Predecessor”). The summary historical financial data for the years ended December 31, 2007, 2008, 2009, 2010, and 2011 and the balance sheet data as of December 31, 2007, 2008, 2009, 2010 and 2011, are derived from the audited financial statements of our Predecessor. Historical results are not necessarily indicative of results we expect in future periods. You should read the following summary financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes appearing elsewhere in this prospectus.
 
                                         
    Predecessor  
    Year Ended December 31,  
    2007     2008     2009     2010     2011  
    Unaudited                          
    (In thousands, except per share amounts)  
 
Results of Operations Data
                                       
Total revenues
  $     $ 57,069     $ 167,904     $ 220,625     $ 299,270  
Costs and expenses
    6,369       64,667       166,686       201,473       291,335  
                                         
Operating income (loss)
    (6,369 )     (7,598 )     1,218       19,152       7,935  
Interest expense
    (8,730 )     (14,752 )     (12,651 )     (11,070 )     (10,839 )
Other income (expense), net
    983       971       988       87       278  
Gain on extinguishment of debt
                            6,954  
                                         
Income (loss) before income taxes
    (14,116 )     (21,379 )     (10,445 )     8,169       4,328  
Income tax provision
                            (856 )
                                         
Net income (loss)
    (14,116 )     (21,379 )     (10,445 )     8,169       3,472  
Less: net income (loss) attributable to non-controlling interest
    (329 )     (5,552 )     (1,730 )     3,351       7,448  
                                         
Net income (loss) attributable to common stockholders
  $ (13,787 )   $ (15,827 )   $ (8,715 )   $ 4,818     $ (3,976 )
                                         
Earnings (loss) per share, basic and diluted
  $ (1.53 )   $ (1.35 )   $ (0.50 )   $ 0.25     $ (0.21 )
                                         
Balance Sheet Data (at period end)
                                       
Total assets
  $ 222,118     $ 372,674     $ 450,618     $ 478,038     $ 507,908  
Working capital
    15,999       (34,668 )     (17,749 )     2,905       (30,629 )
Total debt (including capital leases)
    128,375       183,337       159,730       139,871       244,810  
Total stockholders’ equity
    83,180       168,931       255,333       296,681       168,138  
Other Data
                                       
Tons sold (unaudited)
          1,398       4,674       5,387       7,030  
Net cash provided by (used in):
                                       
Operating activities
  $ (6,109 )   $ (11,079 )   $ 3,054     $ 37,194     $ 48,174  
Investing activities
    (48,418 )     (80,020 )     (62,476 )     (41,755 )     (75,827 )
Financing activities
    67,505       79,402       64,854       (3,935 )     39,132  
Adjusted EBITDA(1) (unaudited)
    (5,724 )     (1,029 )     16,567       41,099       41,023  
Adjusted EBITDA is calculated as follows (unaudited):
                                       
Net income (loss)
  $ (14,116 )   $ (21,379 )   $ (10,445 )   $ 8,169     $ 3,472  
Income tax provision
                            856  
Depreciation, depletion and amortization
    264       5,810       14,464       21,979       31,666  
Interest expense, net
    7,429       14,377       12,482       10,872       10,694  
Non-cash stock compensation expense
    699       163       66       79       1,383  
Non-cash charge related to non-recourse notes
                            217  
Gain on deconsolidation
                            (311 )
Gain on extinguishment of debt
                            (6,954 )
                                         
    $ (5,724 )   $ (1,029 )   $ 16,567     $ 41,099     $ 41,023  
                                         
(1) Adjusted EBITDA is a non-GAAP financial measure, and when analyzing our operating performance, investors Adjusted EBITDA in addition to, and not as an alternative for, operating income and net income (loss) (each as determined in accordance with GAAP). We use Adjusted EBITDA as a supplemental financial measure.
 
Adjusted EBITDA is defined as net income (loss) before net interest expense, income taxes, depreciation, depletion and amortization, non-cash stock compensation expense, non-cash charges related to non-recourse notes, gain on deconsolidation, and gain on extinguishment of debt.


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Adjusted EBITDA, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDA reported by different companies, and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP.
 
For example, Adjusted EBITDA does not reflect:
 
• cash expenditures, or future requirements, for capital expenditures or contractual commitments; changes in, or cash requirements for, working capital needs;
 
• the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt; and
 
• any cash requirements for assets being depreciated and amortized that may have to be replaced in the future.
 
Adjusted EBITDA does not represent funds available for discretionary use because those funds are required for debt service, capital expenditures, working capital and other commitments and obligations. However, our management team believes Adjusted EBITDA is useful to an investor in evaluating our company because this measure:
 
• is widely used by investors in our industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; and
 
• helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure, which is useful for trending, analyzing and benchmarking the performance and value of our business.


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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Selected Historical Consolidated Financial and Operating Data” and our audited and unaudited financial statements and related notes appearing elsewhere in this prospectus. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this prospectus under “Cautionary Statement Concerning Forward-Looking Statements” and “Risk Factors.” We assume no obligation to update any of these forward-looking statements.
 
Overview
 
We are a diversified producer of low chlorine, high sulfur thermal coal from the Illinois Basin with both surface and underground mines. We market our coal primarily to electric utility companies as fuel for their steam-powered generators. Based on 2011 production, we are the sixth largest producer in the Illinois Basin and the second largest in Western Kentucky. We were formed in 2006 to acquire and develop a large coal reserve holding. We commenced production in the second quarter of 2008 and currently operate seven mines, including five surface and two underground, and are seeking permits for three additional mines. We control approximately 326 million tons of proven and probable coal reserves. Our reserves and operations are located in the Western Kentucky counties of Ohio, Muhlenberg, Union and Webster. We also own and operate three coal processing plants which support our mining operations. The location of our coal reserves and operations, adjacent to the Green and Ohio Rivers, together with our river dock coal handling and rail loadout facilities, allow us to optimize our coal blending and handling, and provide our customers with rail, barge and truck transportation options. From our reserves, we mine coal from multiple seams which, in combination with our coal processing facilities, enhances our ability to meet customer requirements for blends of coal with different characteristics.
 
We market our coal primarily to large utilities with coal-fired, base-load, scrubbed power plants under multi-year coal supply agreements. Our multi-year coal supply agreements usually have specific and possibly different volume and pricing arrangements for each year of the agreement. These agreements allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales prices. In 2011, we sold approximately 89% of our coal under multi-year coal supply agreements. At December 31, 2011, we had 10 multi-year coal supply agreements with terms ranging from one to seven years. For the fiscal year ended December 31, 2011, coal sales to LGE and TVA constituted approximately 35% and 28%, respectively, of our total coal revenues. We are contractually committed to sell 8.1 million tons of coal in 2012 and 8.2 million tons of coal in 2013, which represents approximately 88% and 77% of our expected total coal sales in 2012 and 2013, respectively.
 
During 2010 and 2011, we produced 5.6 million and 6.6 million tons of coal, respectively, and during the same periods, we sold 5.4 million and 7.0 million tons of coal, respectively. For the year ended December 31, 2010, our revenue from coal sales was $220.6 million, and we generated operating income of $19.2 million and Adjusted EBITDA of $41.1 million. Our revenue, operating income and Adjusted EBITDA for the year ended December 31, 2011 were $299.3 million, $7.9 million and $41.0 million, respectively. Our coal production increased from 1.4 million tons in 2008 to 6.6 million tons in 2011 through the expansion of our operations by opening new mines.
 
Our principal expenses related to the production of coal are labor and benefits, equipment, materials and supplies (explosives, diesel fuel and electricity), maintenance, royalties and excise taxes. Unlike some of our competitors, we employ a totally non-union workforce. Many of the benefits of our non-union workforce are related to higher productivity and are not necessarily reflected in our direct costs. In addition, while we do not pay our customers’ transportation costs, they may be substantial and are often the determining factor in a coal consumer’s contracting decision. The location of our coal reserves and operations, adjacent to the Green and Ohio Rivers, together with our river dock coal handling and rail loadout facilities, allow us to optimize our coal blending and handling and provide our customers with rail, barge and truck transportation options.


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Evaluating the Results of Our Operations
 
We evaluate the results of our operations based on several key measures:
 
  •  our coal production, sales volume and weighted average sales prices;
 
  •  our cost of coal sales; and
 
  •  our Adjusted EBITDA, a non-GAAP financial measure.
 
We define our coal sales price per ton, or average sales price, as total coal sales divided by tons sold. We review coal sales price per ton to evaluate marketing efforts and for market demand and trend analysis. We define Adjusted EBITDA as our net income (loss) before net interest expense, income taxes, depreciation, depletion and amortization, non-cash stock compensation expense, non-cash charges related to non-recourse notes, gain on deconsolidation, and gain on extinguishment of debt. Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis, the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness, our operating performance and return on investment compared to those of other companies in the coal energy sector, without regard to financing or capital structures, and the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. Adjusted EBITDA has several limitations that are discussed under “Prospectus Summary — Summary Historical and Unaudited Pro Forma Consolidated Financial and Operating Data,” where we also include a quantitative reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measure, which is net income (loss).
 
Coal Production, Sales Volume and Sales Prices
 
We evaluate our operations based on the volume of coal we produce, the volume of coal we sell and the prices we receive for our coal. Because we sell substantially all of our coal under multi-year coal supply agreements, our coal production, sales volume and sales prices are largely dependent upon the terms of those contracts. The volume of coal we sell is also a function of the productive capacity of our mines and changes in our inventory levels and those of our customers.
 
Our multi-year coal supply agreements typically provide for a fixed price, or a schedule of fixed prices, over the contract term. In addition, the contracts typically contain price reopeners that provide for a market-based adjustment to the initial price after the initial years of those contracts have been fulfilled. These contracts will terminate if we cannot agree upon a market-based price with the customer. In addition, many of our multi-year coal supply agreements have full or partial cost pass through or inflation adjustment provisions; specifically, costs related to fuel, explosives and new government impositions are subject to certain pass-through provisions under many of our multi-year coal supply agreements. Cost pass-through provisions typically provide for increases in our sales prices in rising operating cost environments and for decreases in declining operating cost environments. Inflation adjustment provisions typically provide some protection in rising operating cost environments. We also receive premiums, or pay penalties, based upon the actual quality of the coal we deliver, which is measured for characteristics such as heat (Btu), sulfur and moisture content.
 
We evaluate the price we receive for our coal on an average sales price per ton basis. The following table provides operational data with respect to our coal production, coal sales volume and average sales prices per ton for the periods indicated:
 
                         
    Year Ended
 
    December 31,  
    2009     2010     2011  
    (In thousands, except per ton amounts)  
 
Tons of Coal Produced
    4,434       5,645       6,642  
Tons of Coal Sold
    4,674       5,387       7,030  
Tons of Coal Sold Under Multi-Year Agreements
    4,674       4,827       6,241  
Average Sales Price Per Ton
  $ 35.92     $ 40.96     $ 42.57  


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Cost of Coal Sales
 
We evaluate our cost of coal sales on a cost per ton basis. Our cost of coal sales per ton produced represents our production costs divided by the tons of coal we sell. Our production costs include labor and associated benefits, fuel, lubricants, explosives, operating lease expenses, repairs and maintenance, royalties, and all other costs that are directly related to our mining operations, other than the cost of depreciation, depletion and amortization (“DD&A”) expenses. Our production costs also exclude any indirect costs, such as selling, general and administrative (“SG&A”) expenses. Our production costs do not take into account the effects of any of the inflation adjustment or cost pass-through provisions in our multi-year coal supply agreements, as those provisions result in an adjustment to our coal sales price.
 
The following table provides summary information for the dates indicated relating to our cost of coal sales per ton produced:
 
                         
    Year Ended
    December 31,
    2009   2010   2011
    (In thousands, except per ton amounts)
 
Tons of Coal Sold
    4,674       5,387       7,030  
Average Sales Price Per Ton
  $ 35.92     $ 40.96     $ 42.57  
Cost of Coal Sales Per Ton
  $ 27.36     $ 28.19     $ 31.52  
 
Adjusted EBITDA
 
Although Adjusted EBITDA is not a measure of performance calculated in accordance with GAAP, our management believes that it is useful in evaluating our financial performance and our compliance with our existing Senior Secured Credit Facility. Adjusted EBITDA has several limitations that are discussed under “Prospectus Summary — Summary Historical and Unaudited Pro Forma Consolidated Financial and Operating Data,” where we also include a quantitative reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measure, which is net income (loss).
 
Factors that Impact Our Business
 
For the past three years, over 92% of our coal sales were made under multi-year coal supply agreements. We intend to continue to enter into multi-year coal supply agreements for a substantial portion of our annual coal production, using our remaining production to take advantage of market opportunities as they present themselves. We believe our use of multi-year coal supply agreements reduces our exposure to fluctuations in the spot price for coal and provides us with a reliable and stable revenue base. Using multi-year coal supply agreements also allows us to partially mitigate our exposure to rising costs, to the extent those contracts have full or partial cost pass through provisions or inflation adjustment provisions. For example, our contracts with LGE contain provisions that adjust the price paid for our coal in the event there is change in the price of diesel fuel, a key cost component in our coal production. Certain of our other contracts, such as those with TVA, contain provisions that permit us to seek additional price adjustments to account for changes in environmental and other laws and regulations to which we are subject, to the extent those changes increase the cost of our production of coal. For further information about our multi-year coal supply agreements, please see “Business — Sales and Marketing — Multi-Year Coal Supply Agreements.”


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The following table reflects the portion of our anticipated coal production that is committed and priced, committed but unpriced, and uncommitted for sale under our multi-year coal supply agreements for 2012 and 2013.
 
                 
    2012     2013  
    (In millions of tons, except price per ton data)  
 
Committed
    8.1       5.7  
Committed but unpriced
          2.5  
Uncommitted
    1.1       2.5  
                 
Total
    9.2       10.6  
                 
Average price per committed ton
  $ 42.11     $ 42.11  
 
Certain of our multi-year coal supply agreements contain option provisions that give the customer the right to elect to purchase, or defer the purchase of, additional tons of coal each month during the contract term at a fixed price provided for in the contract. Our multi-year coal supply agreements that provide for these option tons typically require the customer to provide us with advance notice of an election to take or defer these option tons. Because the price of these option tons is fixed under the terms of the contract, we could be obligated to deliver coal to those customers at a price that is below the market price for coal on the date the option is exercised. If our customers elect to receive these option tons, we believe we will have the operating flexibility to meet these requirements through increased production. Similarly, short term changes by our customers in the amount of coal they purchase as a result of these option and deferment provisions may affect our average sales price per ton of coal in any given month or similarly narrow window. For example, as discussed in more detail below, our average sales price per ton during the year ended December 31, 2011 was higher than the average sales price per ton during the year ended December 31, 2010, due to higher pricing on our long-term contracts due to the annual increases under the majority of our multi-year coal supply agreements, and spot sales that did not occur in 2010.
 
We believe the other key factors that influence our business are:
 
  •  demand for coal;
 
  •  demand for electricity;
 
  •  economic conditions;
 
  •  the quantity and quality of coal available from competitors;
 
  •  competition for production of electricity from non-coal sources;
 
  •  domestic air emission standards and the ability of coal-fired power plants to meet these standards using coal produced from the Illinois Basin;
 
  •  legislative, regulatory and judicial developments, including delays, challenges to, and difficulties in acquiring, maintaining or renewing necessary permits or mineral or surface rights; and
 
  •  our ability to meet governmental financial security requirements associated with mining and reclamation activities.
 
For additional information regarding some of the risks and uncertainties that affect our business and the industry in which we operate, please see “Risk Factors.”
 
Recent Trends and Economic Factors Affecting the Coal Industry
 
Coal consumption and production in the United States have been driven in recent periods by several market dynamics and trends. Total coal consumption in the United States in 2011 decreased by approximately 42 million tons, or 4.0%, from 2010 levels. The decline in U.S. domestic coal consumption during 2011 was partially a function of switching to other sources of fuel. However, according to the EIA, coal is expected to


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remain the dominant energy source for electric power generation for the foreseeable future. Please read “The Coal Industry — Recent Trends and — Coal Consumption and Demand” for the recent trends and economic factors affecting the coal industry.
 
Results of Operations
 
Factors Affecting the Comparability of Our Results of Operations
 
The comparability of our operating results for the years ending December 31, 2009, 2010 and 2011 is impacted by the opening of additional mines during each of the periods. We began production of coal mid-year 2008 at one underground mine and one surface mine. Our coal production increased substantially from 1.4 million tons in 2008 to 6.6 million tons in 2011. The increase in production was primarily the result of the opening of two additional mines in 2009, a third in 2010, and two additional mines in 2011. Due to these changes in the number of operating mines during the aforementioned periods, it is difficult to provide direct comparisons of reported results during each period. In addition, as discussed in more detail below, from late 2009 through November 2010, we received a price incentive from LGE under one of our multi-year coal supply agreements, which added $3.29 per ton to the sales price under that agreement.
 
Summary
 
The following table presents certain of our historical consolidated financial data for the periods indicated. The following table should be read in conjunction with “Selected Historical Consolidated Financial and Operating Data.”
 
                         
    Year Ended December 31,  
    2009     2010     2011  
    (In thousands, except per share and per ton amounts)  
 
Results of Operations Data
                       
Total revenues
  $ 167,904     $ 220,625     $ 299,270  
Costs and expenses
                       
Costs of coal sales
    127,886       151,838       221,597  
Depreciation, depletion and amortization
    12,480       18,892       27,661  
Asset retirement obligation expenses
    1,984       3,087       4,005  
Selling, general and administrative expenses
    24,336       27,656       38,072  
                         
Total costs and expenses
    166,686       201,473       291,335  
                         
Operating income (loss)
    1,218       19,152       7,935  
Interest expense
    (12,651 )     (11,070 )     (10,839 )
Other income (expense), net
    988       87       278  
Gain on extinguishment of debt
                6,954  
                         
Income (loss) before income taxes
    (10,445 )     8,169       4,328  
Income tax provision
                (856 )
                         
Net income (loss)
    (10,445 )     8,169       3,472  
Less: net (income) loss attributable to non-controlling interest
    (1,730 )     3,351       7,448  
                         
Net income (loss) attributable to common stockholders
  $ (8,715 )   $ 4,818     $ (3,976 )
                         
Earnings (loss) per share, basic and diluted
  $ (0.50 )   $ 0.25     $ (0.21 )
Other Data
                       
Adjusted EBITDA (unaudited)
  $ 16,567     $ 41,099     $ 41,023  
Adjusted EBITDA per ton sold (unaudited)
    3.54       7.63       5.84  


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Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
 
Overview
 
We reported revenue of $299.3 million for the year ended December 31, 2011, compared to $220.6 million for the year ended December 31, 2010. Coal sales increased 30% to 7.0 million tons in 2011, compared to 5.4 million tons in 2010. Our average sales price per ton in 2011 increased 3.9%, or $1.61 per ton, compared to 2010. Our net income decreased from $8.2 million in 2010 to $3.5 million in 2011. Our Adjusted EBITDA decreased slightly to $41.0 million for 2011 from $41.1 million for 2010.
 
Coal Production and Sales Volume
 
Our tons of coal produced increased 17.7% to 6.6 million tons in 2011 from 5.6 million tons in 2010. This increase is primarily attributable to the commencement of production at the Equality Boot, Lewis Creek, and Maddox surface mines, which increased our sales by 2.6 million tons for 2011, as compared to 2010. This increase was partially offset by lower production at our other surface mines as a result of high levels of rainfall, decreases at our East Fork operation of 0.9 million tons as a portion of the mine was depleted and MSHA mandates that impacted production at the Big Run mine. Sales volume during 2011 was slightly lower than anticipated due to weather-induced high water issues on the Green and Ohio Rivers, which delayed barge deliveries to two of our customers. However, the reduction in barge-delivered tons was partially offset by an increase in the number of tons delivered by truck. In addition, maintenance cycles at the primary plants receiving our coal under our contracts with TVA resulted in the deferment or force majeure of approximately 327,000 tons of scheduled deliveries during 2011.
 
Average Sales Price Per Ton
 
Our average sales price per ton increased 3.9% to $42.57 in 2011 from $40.96 in 2010. This $1.61 per ton increase resulted from the combination of: (a) higher pricing on our long-term contracts due to the annual increases under the majority of our multi-year coal supply agreements, and (b) spot sales that did not occur in 2010. These increases were partially offset by the elimination of the $3.29 per ton price adjustment in December 2010 that we received from LGE pending permitting approval of our Equality Boot mine.
 
Revenue
 
Our coal sales revenue for 2011 increased by $78.6 million, or 35.6%, compared to 2010. This increase is primarily attributable to coal sales from our Equality Boot and Lewis Creek mines, which completed development during January 2011 and June 2011, respectively, and contributed an additional $95.6 million of revenue as compared to 2010. The positive effect of the opening of the Equality Boot and Lewis Creek mines was partially offset by record rainfall amounts that hampered barge deliveries, the partial deferment of deliveries of scheduled tons under contract by TVA, Big Rivers and Alcoa.
 
Operating Costs and Expenses (Excluding DD&A Expenses and SG&A Expenses)
 
Operating costs and expenses increased 45.9% to $221.6 million in 2011, from $151.8 million in 2010. This increase was primarily attributable to completing development of our Equality Boot and Lewis Creek mines in January 2011 and June 2011, respectively, which resulted in operating costs of $79.7 million during 2011. On a per ton basis, our cost of coal sales increased during 2011, compared to 2010, from $28.19 per ton to $31.52 per ton, due to unfavorable mining conditions at our surface mines as a result of record rainfall amounts, poor roof conditions at the Big Run mine that required additional support and reduced productivity, and reduced production at the Parkway and East Fork mines. In addition, we experienced higher material and supplies costs in 2011, compared to 2010, related to equipment maintenance expenses and fuel and oil-related expenses. Specifically:
 
  •  Equipment maintenance expenses per ton sold increased 22.7% to $8.71 per ton in 2011 from $7.10 per ton in 2010. The increase of $23.0 million in 2011 as compared to 2010 is primarily the result of the cost of additional equipment at our Equality Boot mine; and


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  •  Fuel and oil-related expenses per ton sold increased 62.5% to $4.11 per ton in 2011 from $2.53 per ton in 2010. The increase of $15.2 million in 2011 as compared to 2010 is the result of higher fuel prices in 2011. A portion of the higher fuel prices will be recovered through higher revenue in future periods through fuel adjustment cost provisions in certain of our multi-year coal supply agreements.
 
Depreciation, Depletion and Amortization
 
DD&A expenses increased by $8.8 million, or 46.4%, during 2011, as compared to the same period in 2010. The primary reason for the increase was a $10.0 million increase in DD&A associated with the Equality Boot and Lewis Creek operations. Amortization expense was also slightly higher as a result of the higher production in 2011. Lower depletion and depreciation expenses were realized at operations with reduced production levels from 2010, thereby offsetting a portion of the increases.
 
Asset Retirement Obligation Expense
 
Asset retirement obligation expense increased by $0.9 million, or 29.7%, in 2011, as compared to 2010. The increase is due primarily to the opening of the Equality Boot and Lewis Creek mines.
 
Selling, General and Administrative Expenses
 
SG&A expenses were $38.1 million for 2011, which was $10.4 million, or 37.7%, higher than 2010. On a cost per ton sold basis for 2011, SG&A expenses were $5.42, compared to $5.13 for 2010. Administrative expenses related to the Equality Boot and Lewis Creek mines accounted for the majority of the increase in costs, and higher coal severance and similar costs that are directly related to the $78.6 million, or 35.6%, increase in total sales for 2011 as compared to 2010.
 
Interest Expense
 
Interest expense was $10.8 million for 2011, as compared to $11.1 million for 2010. The decrease was principally attributable to lower interest rates associated with our Senior Secured Credit Facility as compared to our outstanding debt during 2010 in the form of the promissory notes that were repaid when we entered into our Senior Secured Credit Facility in February 2011. The decline was partially offset by interest expense incurred associated with the long-term obligation to a related party that was recognized as a result of the deconsolidation of Armstrong Resource Partners on October 1, 2011. See “Description of Indebtedness” for a more detailed discussion of our financing activities. As a result of the aforementioned repayment, we recorded a gain on extinguishment of debt of $7.0 million.
 
Income Taxes
 
We recorded an income tax provision of $0.9 million for 2011 while no provision was recorded in 2010. The provision related primarily to current alternative minimum tax and certain state income tax. The current provision is due to taxable income generated in 2011 for certain subsidiaries, compared to taxable losses generated in the same period of the prior year.
 
Adjusted EBITDA
 
Our Adjusted EBITDA for 2011 was $41.0 million, or $5.84 per ton, as compared to $41.1 million, or $7.63 per ton, for 2010. The decrease resulted from the partial deferment of deliveries of scheduled tons under contract by TVA, Big Rivers and Alcoa, the expiration of the price incentive realized during 2010 in connection with one of our LGE sales contracts, and the higher operating costs attributable to the commencement of production at the Equality Boot and Lewis Creek mines during 2011.
 
Production Mix Analysis
 
During 2011 we operated two underground mines (Big Run, and Parkway) and five surface mines (Midway, East Fork, Equality Boot, Lewis Creek, and Maddox). In contrast, during 2010, we only had four


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mines in operation, as development of the Equality Boot mine was not completed until January 2011, Lewis Creek in June 2011, and Maddox in December 2011. The following table provides information concerning our underground mines and surface mines during both 2010 and 2011.
 
                 
    Year Ended December 31,  
    2010     2011  
    (In thousands, except
 
    per ton amounts)  
 
Tons of Coal Sold
               
Underground Mining Operations
    2,066       1,924  
Surface Mining Operations
    3,321       5,106  
Revenue
               
Underground Mining Operations
  $ 102,109     $ 103,537  
Surface Mining Operations
  $ 118,516     $ 195,733  
Production Costs per Ton Sold
               
Underground Mining Operations
  $ 28.54     $ 29.14  
Surface Mining Operations
  $ 21.84     $ 26.37  
Plants, Dock, Other
  $ 3.46     $ 4.39  
 
Sales from our surface mines increased from 3.3 million tons in 2010 to 5.1 million tons in 2011. The increase in tons sold is primarily attributable to the opening of the Equality Boot mine in January 2011 and Lewis Creek in June 2011. Our production costs on a per ton basis at our surface mining operations also increased from $21.84 per ton produced during 2010 to $26.37 per ton produced during 2011. The increase in production costs on a per ton basis at our surface mines is the result of many factors, including higher fuel prices, weather-related impediments, reduced production levels at the East Fork mine as one area of the mine is depleted, and the additional development costs at the Equality Boot mine.
 
Sales from our underground mines declined 0.2 million tons from 2.1 million tons in 2010 to 1.9 million tons in 2011 due primarily to the closure of our Big Run mine in November 2011. Production costs per ton at our underground mines increased from $28.54 per ton produced during 2010 to $29.14 per ton produced during 2011. This increase is primarily the result of increased per ton production costs at our Big Run mine due to the increased material cost for roof bolts and the temporary replacement of a continuous miner unit for a scheduled overhaul prior to relocating to the new underground operation at Kronos resulting in a decrease in productivity.
 
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
 
Overview
 
We reported revenue of $220.6 million for the year ended December 31, 2010, compared to $167.9 million for 2009. Coal sales increased 15% to 5.4 million tons in 2010, as compared to 4.7 million tons in 2009. In addition to increasing our total production, our average sales price per ton in 2010 increased 14%, or $5.04 per ton, compared to 2009. In part as a result of that increase in the average price per ton, we generated income from operations in 2010 of $19.2 million, as compared to $1.2 million in 2009, and our Adjusted EBITDA increased to $41.1 million in 2010, from $16.6 million in 2009.
 
Coal Production and Sales Volume
 
Our tons of coal produced increased 27.3% to 5.6 million tons in 2010 from 4.4 million tons in 2009. This increase is primarily attributable to operations at our East Fork surface mine and our Parkway underground mine. The East Fork mine, which commenced production during the second quarter of 2009, sold 1.7 million tons during 2010, as compared to 0.9 million tons in 2009. Similarly, the Parkway underground mine, which also commenced production during the second quarter of 2009, sold 1.5 million tons in 2010 compared to 0.7 million tons in 2009. Sales volume during the fourth quarter of 2010 was slightly less than anticipated due to a delay in completing the development of our Equality Boot surface mine until 2011 and its


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corresponding effect on budgeted spot market sales. During 2010, sales to our two largest customers, LGE and TVA, accounted for 76% of our total sales, representing 36% and 40% of total sales respectively.
 
Average Sales Price Per Ton
 
Our average sales price per ton increased 14% to $40.96 in 2010 from $35.92 in 2009. This $5.04 per ton increase was primarily the result of a combination of factors, including: (a) a contractually-based price incentive in one of our multi-year coal supply agreements with LGE, which provided for a $3.29 per ton increase from September 2009 through November 2010; (b) the renegotiation of another of our multi-year coal supply agreements, which resulted in an increase in the price per ton of $8.73; (c) a price adjustment with respect to one of our contracts with TVA pursuant to which governmental imposition reimbursements increased our price per ton by $2.00; (d) the annual escalation of prices contained in the majority of our multi-year coal supply agreements, and (e) the execution of a new multi-year coal supply agreement with OMU, pursuant to which we obtained an average sales price of $43.27 per ton. Our ability to obtain short-term sales at prices and volumes higher than in previous years also contributed to the increase in our average sales price per ton.
 
Revenue
 
Our coal sales revenue in 2010 increased by $52.7 million, or 31.4%, compared to 2009. This increase is primarily attributable to coal sales from our East Fork surface mine and Parkway underground mine, both of which were opened during 2009 and thus experienced their first full year of production during 2010. As a result, the combined sales from the East Fork and Parkway mines during 2010 exceeded their aggregate 2009 sales by 1.5 million tons. In addition, our revenue increased as a result of the increase in the average price per ton at which we sold our coal for the reasons set forth immediately above.
 
Operating Costs and Expenses (Excluding DD&A Expenses and SG&A Expenses)
 
In 2010, operating costs and expenses increased 18.7%, to $151.8 million, from $127.9 million in 2009, which was primarily attributed to the 15.3% increase in the total tons of coal we sold during the same period, combined with a 3% per ton increase in our operating costs of $0.83 during 2010, compared to 2009. The increase in our operating costs per ton was due in part to the progression into areas at our Midway and East Fork surface mines where we experienced higher mining ratios, thus increasing the costs required to produce each ton of coal, as well as the need to incur additional overtime labor costs at those surface mines to meet contractual sales requirements in light of the delay in the opening of the Equality Boot surface mine. These per ton cost increases were partially offset by a decrease in the operating costs at our Parkway and Big Run underground mines resulting from improved productivity over the course of 2010 at those mines. In addition, we experienced higher equipment maintenance expenses, fuel and oil-related expenses and royalties in 2010, compared to 2009. Specifically:
 
  •  Equipment maintenance expenses per ton sold increased 11% to $7.10 per ton in 2010 from $6.37 per ton in 2009. The increase of $8.5 million resulted from increased production, as two mines were added during 2009, and higher mining ratios during 2010;
 
  •  Fuel and oil-related expenses per ton sold increased 25% to $2.53 per ton in 2010, from $2.02 per ton in 2009. This represents a $4.2 million increase and is the result of higher production levels and higher fuel prices in 2010; and
 
  •  Royalties (which were incurred as a percentage of coal sales or based on coal volumes) increased $0.17 per ton sold in 2010, compared to 2009, primarily as a result of increased average coal sales prices and our increase in the total volume of production and sales.
 
Depreciation, Depletion and Amortization Expenses
 
DD&A expenses for 2010 were $18.9 million, which was $6.4 million, or 51.4%, higher, as compared to 2009. This was due to a $2.4 million increase in depletion and amortization expense that resulted from our increase in total production in 2010, as well as a $4.0 million increase in depreciation as operations expanded


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with new equipment additions and a full year of expenses that we incurred at our East Fork and Parkway mines, as compared to the partial year of expenses at those mines during 2009, the year in which they commenced production.
 
Asset Retirement Obligation Expense
 
Asset retirement obligation expense increased by $1.1 million, or 55.5%, in 2010, as compared to the prior year. The increase is due primarily to having a full year of expense in 2010 related to the Parkway and East Fork mines, which were added in the second quarter of 2009.
 
Selling, General and Administrative Expenses
 
SG&A expenses were $27.7 million for 2010, which was $3.3 million higher than 2009, but on a cost per ton sold basis decreased from $5.21 per ton to $5.13 per ton. While total sales increased in 2010 by 31.4%, a proportional increase in sales-related costs was partially offset by the generally fixed legal, accounting and other professional fee expenses we incur that were spread across a greater number of tons.
 
Interest Expense
 
Interest expense decreased by $1.6 million in 2010 as compared to 2009, from $12.7 million to $11.1 million, primarily as a result of the repayment in June 2009 of one of the promissory notes made in connection with the acquisition of the Elk Creek Reserves in March 2008.
 
Adjusted EBITDA
 
Our Adjusted EBITDA was $24.5 million higher in 2010 as compared to 2009, increasing 148% from $16.6 million, or $3.54 per ton, to $41.1 million, or $7.63 per ton sold. The increase primarily resulted from the annual increase in the sales prices contained in the majority of our multi-year coal supply agreements, the renegotiation of the sales price under another of our contracts, and a price-based incentive of $3.29 per ton contained in one of our contracts with LGE that increased the sales price under that contract through November 2010.
 
Production Mix Analysis
 
During 2010, we operated two underground mines (Big Run and Parkway) and three surface mines (Midway, East Fork and Equality Boot), although the production from Equality Boot during 2010 was recorded and capitalized as part of the mine’s development costs. In contrast, during 2009, we only had four mines in operation — Big Run, Parkway, Midway and East Fork, and the Parkway mine only began production during April 2009, followed shortly thereafter by the East Fork mine in June 2009. The following table provides information concerning our underground and surface mines during both 2009 and 2010.
 
                 
    Year Ended December 31,
    2009   2010
    (In thousands, except per ton amounts)
 
Tons of Coal Sold
               
Underground Mining Operations
    1,356       2,066  
Surface Mining Operations
    3,318       3,321  
Revenue
               
Underground Mining Operations
  $ 61,373     $ 102,109  
Surface Mining Operations
  $ 106,531     $ 118,516  
Production Costs per Ton Sold
               
Underground Mining Operations
  $ 36.36     $ 28.54  
Surface Mining Operations
  $ 17.38     $ 21.84  
Plants, Dock, Other
  $ 4.38     $ 3.46  


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Our production costs on a per ton basis at our surface mining operations also increased from $17.38 per ton during 2009 as compared to $21.84 per ton during 2010. The increase in production costs on a per ton basis at our surface mines is the result of many factors, including higher stripping ratios encountered in our mining operations, increased explosives costs due to mining wet areas early in the calendar year, and additional overtime costs for labor needed to meet sales contract requirements due to the delay in the opening of the Equality Boot mine.
 
Sales from our underground mines also increased from 1.4 million tons during 2009 to 2.1 million tons during 2010. The majority of the increase in sales is attributable to the opening of our second underground mine at Parkway during June 2009. Production costs per ton at our underground mines decreased from $36.36 per ton during 2009 to $28.54 per ton during 2010, reflecting a 21.5% decrease. This decrease is primarily the result of the lower mining costs experienced at our Parkway mine ($23.84 per ton), which were partially offset by the slightly higher production costs incurred at our Big Run underground mine attributable to unexpected continuous miner repairs, larger than anticipated transportation expenses and the costs of complying with new governmental regulations.
 
Liquidity and Capital Resources
 
Liquidity
 
Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in mining our reserves, as well as complying with applicable environmental laws and regulations. Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, and to service our debt. Our primary sources of liquidity to meet these needs have been cash generated by our operations, borrowings under our Senior Secured Credit Facility and contributions from Yorktown.
 
We believe that cash generated from operations and borrowings under our Senior Secured Credit Facility will be sufficient to meet working capital requirements, anticipated capital expenditures and scheduled debt payments for at least the next several years. We manage our exposure to changing commodity prices for our long-term coal contract portfolio through the use of multi-year coal supply agreements. We enter into fixed price, fixed volume supply contracts with terms greater than one year with customers with whom we have historically had limited collection issues. Our ability to satisfy debt service obligations, to fund planned capital expenditures, to make acquisitions, will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond our control.
 
The principal indicators of our liquidity are our cash on hand and availability under our Senior Secured Credit Facility. As of December 31, 2011, our available liquidity was $29.6 million, comprised of cash on hand of $19.6 million and $10.0 million available under our Senior Secured Credit Facility.
 
Cash Flows
 
The following table reflects cash flows for the applicable periods:
 
                         
    Year Ended December 31,
    2009   2010   2011
    (In thousands)
 
Net cash provided by (used in):
                       
Operating Activities
  $ 3,054     $ 37,194     $ 48,174  
Investing Activities
  $ (62,476 )   $ (41,755 )   $ (75,827 )
Financing Activities
  $ 64,854     $ (3,935 )   $ 39,132  
 
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
 
Net cash provided by operating activities was $48.2 million for the year ended December 31, 2011, an increase of $11.0 million from net cash provided by operating activities of $37.2 million for the same period


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of 2010. The increase in cash provided by operating activities was principally attributable to the expansion of our operations with completing development of the Equality Boot and Lewis Creek mines in January 2011 and June 2011, respectively, and the initiation of development of the Kronos mine in September 2011. The additional mines and higher production levels resulted in increased depreciation, depletion, and amortization expense in the current year, as well as impacted our cash flows from operating assets and liabilities, primarily by leading to an increase in accounts payable and payroll and other accrued incentives in the current year. Negatively impacting cash flows from operations was a year over year decline in net income due to higher overall operating costs and the inclusion of a non-cash gain on extinguishment of debt recognized in the year ended December 31, 2011.
 
Net cash used in investing activities was $75.8 million for the year ended December 31, 2011 compared to $41.8 million for the same period of 2010. This $34.0 million increase was primarily attributable to capital expenditures on equipment and mine development for our Kronos and Lewis Creek mines, as well as the acquisition of additional reserves in December 2011. In addition, we made an investment in an affiliate for the planned construction of an export facility on the lower Mississippi River in 2011 of $2.5 million.
 
Net cash provided by financing activities was $39.1 million for the year ended December 31, 2011 compared to net cash used in financing activities of $3.9 million for the year ended December 31, 2010. This difference was primarily attributable to the closing of our Senior Secured Credit Facility and the repayment of our existing long-term debt in connection therewith. See “Description of Indebtedness” for a more detailed discussion of our financing activities. In addition, we received $20.0 million from Armstrong Resource Partners in December 2011 in connection with the transfer of an undivided interest in certain of our reserves, which will close in March 2012. Partially offsetting the increase in net cash provided by financing activities is the year over year decline in minority contributions of $28.1 million, to $5.0 million in 2011.
 
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
 
Net cash provided by operating activities was $37.2 million for 2010, an increase of $34.1 million from net cash provided by operating activities of $3.1 million for 2009. The increase in cash provided by operating activities was principally attributable to an increase in net income and depreciation, amortization, and depletion expense of $18.6 million and $6.4 million, respectively, due primarily to the continued expansion of our business through the opening of the Equality Boot mine in September 2010 and having a full year of production from the Parkway and East Fork mines, which opened in 2009. In addition, average sales price per ton increased approximately 14% from 2009 to 2010 due primarily to certain price incentives received and annual price escalations contained in our long-term supply contracts. The change in interest on long term obligations of $9.9 million added to the increase in cash flows from operations due to the timing of interest payments. Partially offsetting this increase in cash flows from operations is the decline in the net change in operating assets and liabilities. The change in accounts receivable and inventory of $16.3 million and ($4.2 million), respectively, is due to the timing of shipments at year-end. The increase in the use of cash associated with other non-current assets of $3.0 million relates primarily to an increase in collateral posted on surety bonds and cash bonds to secure the performance of our reclamation obligations as a result of our additional mine being commissioned in 2010. The decline in cash provided by accounts payable and accrued liabilities of $10.1 million is primarily related to the timing of payments associated with general operating expenses and royalties.
 
Net cash used in investing activities was $41.8 million for 2010 compared to $62.5 million for the 2009. This $20.7 million decrease was primarily attributable to a reduction in capital expenditures as higher capital was required in 2009 to start the new mining operations that began in 2009.
 
Net cash used in financing activities was $3.9 million for 2010 compared to net cash provided by financing activities of $64.9 million for the 2009. This difference was primarily attributable to $55.2 million of member contributions recorded during 2009 which were not made during 2010 and an additional $8.5 million of minority contributions made in 2009.


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Senior Secured Credit Facility
 
In February 2011, we repaid certain promissory notes that were delivered in connection with the acquisition of our coal reserves (see “Business — Our Operational History”) and entered into the Senior Secured Credit Facility, which is comprised of the Senior Secured Term Loan and the Senior Secured Revolving Credit Facility. The Senior Secured Term Loan is a $100.0 million term loan, and the Senior Secured Revolving Credit Facility is a $50.0 million revolving credit facility. As a result of the repayment of the existing debt obligations, we recognized a gain of approximately $7.0 million in the quarter ended March 31, 2011. The Senior Secured Term Loan is a five-year term loan that requires principal payments in the amount of $5.0 million each on the first day of each quarter commencing on January 1, 2012 through January 1, 2016, with a final balloon payment due upon maturity on February 9, 2016. Interest payments are also payable quarterly in arrears on the first day of each quarter. The interest rate fluctuates based on our leverage ratio and the applicable interest option elected. The interest rate as of December 31, 2011 was 5.25%. The Senior Secured Revolving Credit Facility provides for quarterly interest payments in arrears that fluctuate on the same terms as our term loan. The Senior Secured Revolving Credit Facility also provides for a commitment fee based on the unused portion of the facility at certain times. As of December 31, 2011, we had $40.0 million outstanding, with $10.0 million available for borrowing under our Senior Secured Revolving Credit Facility. The obligations under the credit agreement are secured by a first lien on substantially all of our assets, including but not limited to certain of our mines, coal reserves and related fixtures. The credit agreement contains certain customary covenants as well as certain limitations on, among other things, additional debt, liens, investments, acquisitions and capital expenditures, future dividends, and asset sales. We incurred approximately $3.3 million in fees related to the new credit agreement which will be amortized over the term of the Senior Secured Term Loan. We entered into an interest rate swap agreement, effective January 1, 2012, to hedge our exposure to rising interest rates. Pursuant to this agreement, we are required to make payments at a fixed interest rate of 2.89% to the counterparty on an initial notional amount of $47.5 million (amortizing thereafter) in exchange for receiving variable payments based on the greater of 1.0% or the three-month LIBOR rate, which was 0.581% as of December 31, 2011. This agreement has quarterly settlement dates and matures on February 9, 2016.
 
On July 1, 2011, we entered into the First Amendment to our Senior Secured Credit Facility which, among other things, amended the provisions of the loan documents so as to permit an offering of our securities and the completion of the Reorganization. The amendment also made certain changes to our financial covenants, including our maximum leverage ratio. In addition, our interest rate increased to 5.75%, which can be reduced in future periods to the extent our results improve. Pursuant to such provision, on November 15, 2011, our interest rate was reduced to 5.25%. We incurred approximately $1.1 million of fees related to this amendment, which will be amortized over the remaining term of the Senior Secured Term Loan. We entered into the Second Amendment to our Senior Secured Credit Facility on September 29, 2011, pursuant to which restrictions to the consummation of this offering were eliminated. Additionally, on December 29, 2011, we entered into the Third Amendment to our Senior Secured Credit Facility which, among other things, amended the provisions of the loan documents so as to permit the acquisition of additional coal reserves. On February 8, 2012, we entered into the Fourth Amendment to our Senior Secured Credit Facility which, among other things, amended the provisions of the loan documents so as to modify the consolidated EBITDA threshold, eliminate the minimum fixed charge coverage ratio, add a minimum interest coverage ratio beginning in 2013 and make certain changes to our financial covenants, including our maximum leverage ratio and our minimum consolidated EBITDA. In connection with entry into the Third and Fourth Amendments to the Senior Secured Credit Facility, we paid fees in the aggregate amount of $1.125 million.
 
Contractual Obligations
 
We have various commitments primarily related to long-term debt, including capital leases and operating lease commitments related to equipment. We expect to fund these commitments with cash on hand, cash


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generated from operations and borrowings under our Senior Secured Credit Facility. The following table provides details regarding our contractual cash obligations as of December 31, 2011:
 
                                         
    Payments Due by Period
    Total   Less Than One Year   1-3 Years   3-5 Years   More Than Five Years
    (In thousands)
 
Long-term debt obligations (principal and interest)
  $ 134,832     $ 39,759     $ 51,099     $ 43,950     $ 24  
Long-term obligations to related party(1)
    246,170       7,448       15,768       13,284       209,670  
Operating lease obligations
    53,423       16,906       28,268       8,249        
Capitalized lease obligations (principal and interest)
    15,720       5,126       8,070       2,400       124  
Purchase obligations
    10,164       10,164                    
                                         
Total
  $ 460,309     $ 79,403     $ 103,205     $ 67,883     $ 209,818  
                                         
 
 
(1) Long-term obligation to related party is an obligation associated with a financing arrangement with Armstrong Resource Partners. Payments due are estimated based on current mine plans and estimated sales prices of the coal and will be revised as mine plans change. For the foreseeable future, we are deferring the payment of any production royalty amounts due to Armstrong Resource Partners. In consideration for granting the option to defer these payments, we granted to Armstrong Resource Partners the option to acquire an additional undivided interest in certain of our coal reserves in Muhlenberg and Ohio Counties by engaging in a financing arrangement, under which we would satisfy payment of any deferred fees by selling part of our interest in the aforementioned coal reserves at fair market value for such reserves determined at the time of the exercise of such options.
 
Capital Expenditures
 
Our mining operations require investments to expand, upgrade or enhance existing operations and to comply with environmental regulations. Our anticipated total capital expenditures for 2012 are estimated in a range of $40.0 to $50.0 million. Management anticipates funding 2012 capital requirements with cash flows provided by operations, borrowing available under our Senior Secured Credit Facility as discussed below, leases and the proceeds of this offering. We will continue to have significant capital requirements over the long-term, which may require us to incur debt or seek additional equity capital. The availability and cost of additional capital will depend upon prevailing market conditions, the market price of our securities and several other factors over which we have limited control, as well as our financial condition and results of operations.
 
Kronos Underground Mine Development
 
Mine development costs are capitalized until production commences, other than production incidental to the mine development process, and are amortized on a units of production method based on the estimated proven and probable reserves. Mine development costs represent costs incurred in establishing access to mineral reserves and include costs associated with sinking or driving shafts and underground drifts, permanent excavations, roads and tunnels. The end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Our estimate of when construction of the mine for economic extraction is substantially complete is based upon a number of assumptions, such as expectations regarding the economic recoverability of reserves, the type of mine under


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development, and completion of certain mine requirements, such as ventilation. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase.
 
The Kronos underground mine currently is a three unit underground mine. The majority of the equipment for the mine will be transferred from our existing Big Run underground mine. Notwithstanding the fact that we will initially begin production on the Kronos mine as a three unit mine, the infrastructure will be developed so as to facilitate expansion for up to four units as demand warrants such increased production. The saleable production from the mine is estimated to be 1.2 million saleable tons annually. As and when the mine is expanded to four units, production is estimated to double to approximately 2.3 million tons annually. The estimated total cost of development of the Kronos underground mine, including the planned expansion to four units, is approximately $60 million. Capitalized development costs in 2011 were $24.8 million.
 
Off-Balance Sheet Arrangements
 
In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as surety bonds and performance bonds. No liabilities related to these arrangements are reflected in our consolidated balance sheet, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.
 
Federal and state laws require us to secure certain long-term obligations such as mine closure and reclamation costs and other obligations. We typically secure these obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive for us than the alternative of posting a 100% cash bond. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral. We also post performance bonds to secure our performance of various contractual obligations.
 
As of December 31, 2011, we had approximately $16.5 million in surety bonds outstanding to secure the performance of our reclamation obligations, which were supported by approximately $4.0 million of cash posted as collateral. As of December 31, 2011, we had approximately $1.0 million of performance bonds outstanding, none of which were secured by collateral.
 
Critical Accounting Policies and Estimates
 
Our preparation of financial statements in conformity with GAAP requires that we make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. 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. The most significant areas requiring the use of management estimates and assumptions relate to units-of-production amortization calculations, asset retirement obligations, useful lives for depreciation of fixed assets and estimates of fair values for asset impairment purposes. This section describes those accounting policies and estimates that we believe are critical to understanding our historical consolidated financial statements and that we believe will be critical to understanding our consolidated financial statements subsequent to this offering.
 
Inventory
 
Inventory consists of coal that has been completely uncovered or that has been removed from the pit and stockpiled for crushing, washing or shipment to customers. Inventory also consists of supplies, primarily spare parts and fuel. Inventory is valued at the lower of average cost or market. The cost of coal inventory includes labor, equipment operating expenses and certain transportation and operating overhead.


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Property, Plant and Equipment
 
Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of existing plant and equipment are capitalized. Maintenance and repairs that do not extend the useful life or increase productivity are charged to operating expense as incurred. Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets.
 
There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may vary considerably from actual results. These factors and assumptions relate to: geological and mining conditions, which may not be fully identified by available exploration data and/or differ from our experiences in areas where we currently mine; the percentage of coal in the ground ultimately recoverable; historical production from the area compared with production from other producing areas; the assumed effects of regulation and taxes by governmental agencies; and assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes and development and reclamation costs.
 
For these reasons, estimates of the recoverable quantities of coal attributable to any particular group of properties, classifications of reserves based on risk of recovery 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 substantially. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. Certain account classifications within our financial statements such as depreciation, depletion, and amortization and certain liability calculations such as asset retirement obligations may depend upon estimates of coal reserve quantities and values. Accordingly, when actual coal reserve quantities and values vary significantly from estimates, certain accounting estimates and amounts within our consolidated financial statements may be materially impacted. Coal reserve values are reviewed annually, at a minimum, for consideration in our consolidated financial statements.
 
Advance Royalties
 
A substantial portion of our reserves are leased. Advance royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable through a reduction in royalties payable on future production. Amortization of leased coal interests is computed using the units-of-production method over estimated recoverable tonnage.
 
Long-Lived Assets
 
We review the carrying value of long-lived assets and certain identifiable intangibles whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Long-lived assets and certain intangibles are not reviewed for impairment unless an impairment indicator is noted. Several examples of impairment indicators include: a significant decrease in the market price of a long-lived asset; a significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset; or a significant adverse change in the extent or manner in which a long-lived is being used or in its physical condition. The foregoing factors are not all inclusive, and management must continually evaluate whether other factors are present that would indicate a long-lived asset may be impaired. The amount of impairment is measured by the difference between the carrying value and the fair value of the asset. We have not recorded an impairment loss for any of the periods presented.
 
Asset Retirement Obligation
 
Our asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with applicable reclamation laws in the U.S. as defined by each mining permit. Asset retirement obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, discounted using a credit-adjusted, risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs, or changes in timing of the reclamation activities), the obligation and


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asset are revised to reflect the new estimate after applying the appropriate credit-adjusted, risk-free rate. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Asset retirement obligation expense for the year ended December 31, 2011 was $4.0 million. See Note 19 to our consolidated financial statements for additional details regarding our asset retirement obligations.
 
Income Taxes
 
We account for income taxes in accordance with accounting guidance which requires deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. The guidance also requires that deferred tax assets be reduced by a valuation allowance if it is “more likely than not” that some portion or the entire deferred tax asset will not be realized. In our evaluation of the need for a valuation allowance, we take into account various factors, including the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in our evaluation, we may record a change in valuation allowance through income tax expense in the period such determination is made. We believe that the judgments and estimates are reasonable; however, actual results could differ.
 
Revenue Recognition and Accounts Receivable
 
Revenues from coal sales are recognized when title passes to the customer as the coal is shipped. 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.
 
Our accounts receivable are recorded at the invoiced amount. Our sales are primarily to large utilities that have excellent credit. We evaluate the need for an allowance for doubtful accounts based on anticipated recovery and industry data. If any of our customers were to encounter financial difficulties that restricted their ability to make payments, our estimate of an appropriate allowance for doubtful accounts could change. As of December 31, 2011 and 2010, we had not established an allowance for accounts receivable.
 
Stock-Based Compensation
 
We account for stock-based compensation in accordance with the authoritative guidance on stock compensation. Under the fair value recognition provisions of this guidance, stock-based compensation is measured at the grant date based on the fair value of the award and is recognized as expense, net of estimated forfeitures, over the requisite service period, which is generally the vesting period of the respective award.
 
The primary stock-based compensation tool used by us for our employee base is through awards of restricted stock. The majority of restricted stock awards generally cliff vest after two to three year of service. The fair value of restricted stock is equal to the fair market value of our common stock at the date of grant and is amortized to expense ratably over the vesting period, net of forfeitures. Because our common stock is not publicly traded, we must estimate the fair market value based on multiple valuation methods. The valuations of our common stock were determined in accordance with the guidelines outlined in the American Institute of Certified Public Accountants Practice Aid, Valuation of Privately-Held-Company Equity Securities Issued as Compensation by a third-party valuation specialist. The assumptions we use in the valuation model are based on future expectations combined with management judgment. In the absence of a public trading market, our board of directors with input from management exercised significant judgment and considered numerous objective and subjective factors to determine the fair value of our common stock as of the date of each option grant, including the following factors:
 
  •  our operating and financial performance;
 
  •  current business conditions and projections;


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  •  the likelihood of achieving a liquidity event for the shares of common stock underlying these restricted stock grants, such as an initial public offering or sale of our company, given prevailing market conditions;
 
  •  our stage of development;
 
  •  any adjustment necessary to recognize a lack of marketability for our common stock;
 
  •  the market performance of comparable publicly traded companies; and
 
  •  the U.S. and global capital market conditions.
 
We granted restricted stock awards with the following grant date fair values between January 1, 2009 and the date of this prospectus:
 
                 
    Number of
   
    Shares
   
    Underlying the
  Grant-Date
Grant Date
  Award   Fair Value
 
January 2010
    18,500     $ 6.49  
August 2010
    16,650       5.95  
June 2011
    83,250       13.93  
September 2011
    9,250       14.80  
 
The fair value of our common stock was determined by our Board of Directors based on multiple valuation methodologies utilizing both quantitative and qualitative factors. Significant factors considered by our board of directors and the valuation methodology used to determine the fair value of our common stock at these grant dates include:
 
January 2010
 
In September 2009, we sold 1,387,500 shares of common stock to our majority stockholder at $10.81 per share. As our financial forecast and expected growth rate had not materially changed from this date and the demand for Illinois Basin coal remained strong, we utilized $10.81 was a reasonable undiscounted fair value of our common stock for the restricted stock grant made in January 2011. Through the use of a third party specialist, a non-marketability discount of 40% was derived due to the unlikely nature of a liquidity event occurring in the near future, resulting in an overall fair value of $6.49 per share.
 
August 2010
 
Between February 2010 and August 2010, the economic factors impacting our business had not changed significantly, and, thus, we assumed the undiscounted fair value of our common stock had remained unchanged at $10.81 per share. Through the use of a third party specialist, a non-marketability discount of 45% was derived based on the likelihood of a liquidity event, resulting in an overall fair value of $5.95 per share.
 
June 2011
 
Between September 2010 and June 2011, we experienced significant growth in our business due primarily to two additional mines commencing operations. In addition, due to the continued strength in the coal markets during this period, we concluded the likelihood of a liquidity event had increased in order to support our future growth plans. In June 2011, we granted restricted stock awards to certain executive and non-executive employees. The undiscounted fair value of our common stock, which totaled $17.41 per share, was determined by a third party specialist based on both a market approach using the comparable company method and an income approach using the discounted cash flow method. Given a liquidity event was expected to occur within approximately one year, a non-marketability discount of 20% was applied to determine an overall fair value per share. Based on this valuation and the factors discussed above, the overall fair value per share was determined to be $13.93.


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September 2011
 
Between July 2011 and September 2011, our outlook on the industry remained positive and the likelihood of a liquidity event became more probable. In September 2011, a non-executive employee was granted a restricted stock award. As our financial forecasts and expectations for growth had not changed significantly from June 2011, we concluded the undiscounted fair value of our common stock had remained unchanged from our previous grant at $17.41 per share. Given a liquidity event was expected to occur within approximately six to nine months, a non-marketability discount of 15% was determined by a third party specialist and applied to determine an overall fair value per share. Based on this valuation and the factors discussed above, the overall fair value per share was determined to be $14.80.
 
Stock compensation expense totaled $1.4 million, $0.1 million, and $0.1 million for the years ended December 31, 2011, 2010, and 2009, respectively. Stock compensation expense to be recognized on non-vested restricted stock awards as of December 31, 2011 was approximately $1.0 million.
 
New Accounting Standards Issued and Adopted
 
In January 2010, the Financial Accounting Standards Board (the “FASB”) issued accounting guidance that requires new fair value disclosures, including disclosures about significant transfers into and out of Level 1 and Level 2 fair-value measurements and a description of the reasons for the transfers. In addition, the guidance requires new disclosures regarding activity in Level 3 fair value measurements, including a gross basis reconciliation. The new disclosure requirements became effective for interim and annual periods beginning January 1, 2010, except for the disclosure of activity within Level 3 fair value measurements, which became effective January 1, 2011. The new guidance did not have an impact on our consolidated financial statements.
 
New Accounting Standards Issued and Not Yet Adopted
 
In June 2011, the FASB amended requirements for the presentation of other comprehensive income (loss), requiring presentation of comprehensive income (loss) in either a single, continuous statement of comprehensive income or on separate but consecutive statements, the statement of operations and the statement of other comprehensive income (loss). The amendment is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, or March 31, 2012 for us. The adoption of this guidance will not impact our financial position, results of operations or cash flows and will only impact the presentation of other comprehensive income (loss) on the financial statements.
 
In May 2011, the FASB amended the guidance regarding fair value measurement and disclosure. The amended guidance clarifies the application of existing fair value measurement and disclosure requirements. The amendment is effective for interim and annual periods beginning after December 15, 2011, or March 31, 2012 for us. Early adoption is not permitted. The adoption of this amendment is not expected to materially affect our consolidated financial statements.
 
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 risks and interest rate risk.
 
Commodity Price Risk
 
We sell most of the coal we produce under multi-year coal supply agreements. Historically, we have principally managed the commodity price risks from our coal sales by entering into multi-year coal supply agreements of varying terms and durations, rather than through the use of derivative instruments. See “— Results of Operations — Factors that Impact our Business” for more information about our multi-year coal supply agreements.
 
Some of the products used in our mining activities, such as diesel fuel, explosives and steel products for roof support used in our underground mining, are subject to price volatility. Through our suppliers, we utilize


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forward purchases to manage a portion of our exposure related to diesel fuel volatility. A hypothetical increase of $0.10 per gallon for diesel fuel would have reduced net income by $0.9 million for the year ended December 31, 2011. A hypothetical increase of 10% in steel prices would have reduced net income by $0.8 million for the year ended December 31, 2010. A hypothetical increase of 10% in explosives prices would have reduced net income by $1.4 million for the year ended December 31, 2011.
 
Interest Rate Risk
 
We have exposure to changes in interest rates on our indebtedness associated with our Senior Secured Credit Facility. In 2011, we entered into an interest rate swap agreement, effective January 1, 2012, to hedge our exposure to rising interest rates. Pursuant to this agreement, we are required to make payments at a fixed interest rate of 2.89% to the counterparty on an initial notional amount of $47.5 million (amortizing thereafter) in exchange for receiving variable payments based on the greater of 1.0% or the three-month LIBOR rate, which was 0.581% as of December 31, 2011. This agreement has quarterly settlement dates and matures on February 9, 2016.
 
A hypothetical increase or decrease in interest rates by 1% would have changed our interest expense by $1.5 million, $1.7 million, and $1.9 million for the years ended December 31, 2011, 2010 and 2009, respectively.
 
Seasonality
 
Our business has historically experienced some 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 floods or blizzards, can impact our ability to mine and ship our coal and our customers’ ability to take delivery of coal.


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THE COAL INDUSTRY
 
Overview
 
Coal is an abundant natural resource that serves as the primary fuel source for the generation of electric power and as a key ingredient in the production of steel. According to the World Coal Association (“WCA”), approximately 42% of the world’s electricity generation and approximately 68% of global steel production is fueled by coal. Global hard coal and brown coal production totaled more than 7.5 billion tons in 2009 according to the WCA.
 
Coal is the most abundant fossil fuel in the United States. The EIA estimates that there are approximately 260 billion tons of recoverable coal reserves in the United States, more than in any other country, which represents over 200 years of domestic coal supply based on current production rates. The United States is second only to China in annual coal production, producing approximately 1.1 billion tons in 2011, according to the EIA.
 
Coal is ranked by heat content, with anthracite, bituminous, subbituminous and lignite coal representing the highest to lowest carbon and heat ranking, respectively. Coal is also characterized by end use market as either thermal coal or metallurgical coal. Thermal coal is used by utilities and independent and industrial power producers to generate electricity and/or steam or heat and metallurgical coal is used by steel companies to produce metallurgical coke for use in the steel making process. Important factors in evaluating thermal coal quality are its Btu or heat content, sulfur, ash and moisture content, while metallurgical coal is evaluated on the additional metrics of contained volatile matter and coking characteristics, including expansion, plasticity and strength.
 
Electricity generation accounts for 68% of global coal consumption (2008) while industrial consumption accounts for nearly 36% of global coal production. Thermal coal’s abundance and relatively wide in-situ global resource distribution have contributed to its relative ease of availability and competitive cost versus other electricity generating fuels. Global thermal coal trade is expected to grow to 1.1 billion annual tons in 2016 from 850 million tons in 2010, driven largely by increased electricity demand in the developing world, a significant portion of which is expected to be supplied by coal-fired power plants. According to the EIA, U.S. domestic thermal coal market consumption accounts for approximately 86% of U.S. domestic coal production, and coal-fired electricity generation is expected to continue to be the largest single fuel source of U.S. electricity (39% in 2035).
 
Recent Trends
 
U.S. and international coal market supply, demand and prices are influenced by many factors including relative coal quality, available capacity and costs of transportation and related infrastructure (such as rail, barge and river or export terminals), mining production costs, and the relative costs of generating electricity with competing fuels (natural gas, fuel oil, hydro, nuclear and renewable such as wind and solar power). U.S. domestic thermal coal demand and global thermal coal demand are strongly correlated with the pace of domestic and global economic growth.
 
Our operations are located in the Western Kentucky region of the Illinois Basin and we produce thermal coal for consumption by electricity generators operating scrubbed power plants in the Eastern United States and along the Mississippi River and for international coal consumers who are capable of utilizing our coal. We compete with other producers of similar quality coal in the Illinois Basin, as well as with producers of other thermal coal in other U.S. production regions including the Powder River Basin and Northern, Central and Southern Appalachia.
 
According to the EIA, the U.S. coal industry produced approximately 1.1 billion tons of coal in 2011, a substantial majority of which was sold by U.S. coal producers to operators of electricity generation plants. Coal-fired electricity generation is the largest component of total world electricity generation. The following market dynamics and trends currently impact thermal coal consumption and production in the United States and are reshaping competitive advantages for coal producers.
 
  •  Stable long-term outlook for U.S. thermal coal market.  According to the EIA, coal-fired electricity generation accounted for approximately 44% of all electricity generation in the United States in 2011. Coal continues to be the lowest cost fossil fuel source of energy for electric power generation. Despite recent increases in generation from natural gas, as well as federal and state subsidies for the construction and


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  operation of renewable energy, the EIA projects that coal-fired generation will continue to remain the largest single source of electricity generation in 2035.
 
  •  Increasing demand for coal produced in the Illinois Basin.  According to Wood Mackenzie, a leading commodities consultancy, demand for coal produced from the Illinois Basin is expected to grow by 48% from 2010 through 2015 and by 108% from 2010 through 2030. We believe this is due to a combination of factors including:
 
  è  Significant expansion of scrubbed coal-fired electricity generating capacity.  The EIA forecasts a 32% increase in FGD installed on the coal-fired generation fleet from 168 gigawatts in 2009 to 222 gigawatts, or 70% of all U.S. coal-fired capacity in the electric sector, by 2035, as electricity generation operators invest in retrofit emissions reduction technology to comply with new EPA regulations under the Cross-State Air Pollution Rule and the proposed Utility Boiler MACT regulations. Illinois Basin coal generally has a higher sulfur content per ton than coal produced in other regions. However, we believe that FGD utilization will enable operators to use the most competitively priced coal (on a delivered cents per million Btu basis) irrespective of sulfur content, and thus lead to a strong increase in demand for Illinois Basin coal.
 
  è  Declines in Central Appalachian thermal coal production.  Wood Mackenzie forecasts that production of Central Appalachian thermal coal will continue to decline, falling from 128 million tons in 2010 to 64 million tons in 2015, due to reserve depletion, regulatory-driven decreases in Central Appalachian surface thermal coal production and more difficult geological conditions. These factors are expected to result in significantly higher mining costs and prices for Central Appalachian thermal coal. We believe this will lead to an increase in demand for thermal coal from the Illinois Basin due to its comparatively lower delivered cost to the major Eastern U.S. utilities who are currently the principal users of thermal coal from Central Appalachia.
 
  è  Growing demand for seaborne thermal coal.  Global trade in thermal coal accounted for nearly 70% of all global coal exports in 2010 and is projected to rise from 850 million tons in 2010 to 1.1 billion tons by 2016. We believe that limitations on existing global export coal supply, infrastructure constraints, relative exchange rates, coal quality and cost structure could create significant thermal coal export opportunities for U.S. coal producers, including Illinois Basin coal producers, particularly those similar to us with transportation access to the Mississippi River and to rail connecting to Louisiana export terminals. In addition, we believe that certain domestic users of U.S. thermal coal will need to seek alternative sources of domestic supply as an increasing amount of domestic coal is sold in global export markets.
 
Coal Consumption and Demand
 
The vast majority of thermal coal consumed in the United States is used to generate electricity, with the balance used by a variety of industrial users to heat and power a range of manufacturing and processing facilities. Metallurgical coal is primarily used in steelmaking blast furnaces. In 2011, coal-fired power plants produced approximately 44% of all electric power generation, more than natural gas and nuclear, the two next largest domestic fuel sources, combined. Thermal coal used by electric utilities and other power producers accounted for 935 million tons or 93% of total coal consumption in 2011.
 
Because coal-fired generation is used in most cases to meet base load electricity demand requirements, coal consumption has generally grown at the pace of electricity demand growth. Among coal’s primary advantages are its relatively low cost and ease of transportation ability compared to other fuels used to generate electricity. According to the EIA, coal is expected to remain the dominant energy source for electric power generation for the foreseeable future.
 
Over the long term, the EIA forecasts in its 2012 reference case that total coal consumption will grow by approximately 10% from 2010 through 2035, primarily due to steady increases in coal-fired electric power generation and the introduction of coal-to-liquids plants.


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Illinois Basin Coal Market
 
We market and deliver our coal to electricity generating customers both in close proximity to our production area in Western Kentucky along the Green and Ohio Rivers and to customers along the Mississippi River and in the Southeastern United States. In 2010, 49.1% of the electricity in our market area was generated by coal-fired power plants. The table below compares the total electricity generation in our market area to that which was coal-fired for 2010.
 
                         
    2010 Total
             
    Electricity
    2010 Coal-Fired Electricity Generation  
    Generation
          Percent of
 
    GWh     GWh     Total  
 
Total-Our Primary Market Area(1)
    2,765,970       1,357,670       49.1 %
Total United States
    4,120,028       1,850,750       44.9 %
 
 
(1) Any state east of the Mississippi River, as well as Minnesota, Iowa, Missouri, Arkansas and Louisiana.
 
Source: EIA
 
The number of new coal-fired power plants in the Illinois Basin coal market is expected to increase, as eight new plants have recently been built or are permitted and under construction. The table below represents the EIA Form 860 information and/or public filing data on these new and under construction coal-fired units, which represent over 5,000mw of nameplate capacity.
 
                             
                Under
         
                Construction
  MW
    Effective
Utility Name
 
Plant Name
  State   County   Region   Nameplate     Year
 
Virginia Electric & Power Co. 
  Virginia City Hybrid Energy Center   VA   Wise   RFC     585     2012
Duke Energy Carolinas LLC
  Cliffside   NC   Cleveland   SERC     800     2011
Duke Energy Indiana Inc. 
  Edwardsport (IGCC)   IN   Knox   RFC     618     2011
Cash Creek Generating LLC
  Cash Creek (Coal Gasification)   KY   Henderson   SERC     640     2011
GenPower
  Longview Power LLC   WV   Monongalia   RFC     695     2011
Louisiana Gas & Electric
  Trimble County   KY   Trimble   SERC     834     2010
City Utilities of Springfield
  Southwest Power Station   MO   Greene   SERC     300     2010
Dynegy Services Plum Point Inc. 
  Plum Point Energy Station   AR   Mississippi   SERC     665     2010
 
 
Source: EIA
 
More importantly, the progressive tightening by the EPA of SO2, NOx and other hazardous air pollutant emissions standards from coal-fired electricity generation plants is expected to result in additional significant increases in the number of generating stations retrofitted with FGD systems.
 
U.S. Scrubber Market
 
The 1990 amendments to the Clean Air Act imposed progressively stringent regulations on the emissions of SO2 and NOx. Among the coal-fired electricity generation industry’s response to these regulations was the development of emission control technologies to reduce SO2 emissions released in the burning of coal, such as FGD systems, also known as “scrubbers.” Scrubbers have the additional benefit of being able to reduce mercury emissions, which are soon to be restricted under the EPA’s hazardous air pollutants regulations.
 
To implement requirements under the Clean Air Act, in July 2011, the EPA adopted the CSAPR (aimed at SO2 and NOx). In December 2011, the U.S. Court of Appeals for the District of Columbia Circuit issued a ruling to stay the CSAPR pending judicial review. The EPA is also presently developing additional rules to further reduce the release of certain combustion by-product emissions from fossil fuel power plants. These rules include the proposed Utility Boiler MACT that would regulate the emission of other air pollutants, including mercury and other metals, fine particulates, and acid gases such as hydrogen chloride (HCl).
 
To comply with the expected tightening of emissions limitations, operators of coal-fired electricity generation have increasingly invested in FGD, selective and non-selective catalytic reduction systems and


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other advanced control technologies at their large, base load power plants. 199gw of the current 316gw of U.S. coal-fired generation is presently equipped with FGD emissions systems. We believe that with the implementation of the CSAPR and MACT, new FGD systems will likely be installed on additional coal-fired generation increasing the total amount of generation capacity to approximately 70% of all U.S. capacity in the electric sector capacity by 2035.
 
Today, the number of scrubbers being installed at coal-fired power plants across the United States is growing, and the operating and economic profile use of this technology has become well understood and broadly applied. We expect that the continuation of this trend will substantially increase the demand for higher sulfur coal given the competitive cost of Illinois Basin coal, and will expand the competitive reach of our coal and our primary market area.
 
The following table contains Wood Mackenzie’s forecasts of additional generation capacity by installing and utilizing FGD units and the related affected coal consumption potential from 2010 through 2014. The scrubbed generation unit additions are expected to impact over 250 million tons of coal consumption at these units which may position higher sulfur coal from the Illinois Basin to effectively compete for a greater share of supply to these units.
 
Projected Affected Tons Due to Announced Scrubbing
(in millions)
 
                                         
    2010
    2011
    2012
    2013
    2014
 
    Actual     Forecast     Forecast     Forecast     Forecast  
 
MW Scrubbed (U.S. Total)
    37,448       10,629       9,940       11,967       9,121  
Coal Tons Affected (Million Tons)
    120       34       32       38       29  
 
 
Source: Wood Mackenzie Illinois Basin Market Outlook, September 2011
 
Wood Mackenzie forecasts that the U.S. domestic electricity generation coal consumption will grow from a projected 942 million tons in 2012 to 985 million tons by 2015. More importantly, the Wood Mackenzie forecast projects Illinois Basin coal production growth from 130 million tons in 2012 to 167 million tons by 2015 (28% growth) and then to over 200 million tons by 2020.
 
Long-Term U.S. Thermal Coal Outlook — Fall 2011: Summary Table of Key Data
(in millions)
 
                                                         
    2012     2013     2014     2015     2020     2025     2030  
 
Supply (Mst)
    1,109       1,113       1,108       1,145       1,139       1,179       1,240  
                                                         
Powder River Basin
    487       483       486       508       481       508       552  
Central Appalachia
    89       76       64       64       46       56       71  
Illinois Basin
    130       144       157       167       204       216       224  
Northern Appalachia
    121       129       134       136       132       125       124  
Metallurgical (not including Thermal Cross Over)
    84       82       69       70       81       87       93  
Imports
    8       5       3       3       5       5       5  
Other (including Refuse or Petcoke)
    190       195       196       197       190       131       171  
Stockpile Increase (Decrease)
                                         
Demand (Mst)
    1,109       1,113       1,108       1,145       1,139       1,179       1,240  
                                                         
Electricity Generation
    942       942       967       985       954       837       794  
Industrial
    52       51       52       52       53       54       54  
Thermal Export
    32       38       21       38       52       200       299  
Metallurgical Demand (includes Thermal Cross Over)
    84       82       69       70       81       87       93  
 
 
Source: Wood Mackenzie Long Term US Thermal Coal Market Outlook, October 2011


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Wood Mackenzie estimates that demand for Illinois Basin coal will grow at a compound annual rate of 3.7%, taking total consumption from 117 million tons in 2012 to more than 225 million tons by 2030. This is compared to total U.S. coal production, which Wood Mackenzie estimates will grow at a compound annual rate of 0.6% over the same period. Importantly, Illinois Basin coal production is projected to grow more sharply over the 2012-2020 period (6.7% CAGR) than over the latter part of the 20-year projection period.
 
(GRAPHICS)
 
 
Source: Wood Mackenzie
 
Global Thermal Coal Markets
 
Global coal production accounted for 30% of global primary energy consumption in 2010, according to BP.
 
2010 Global Primary Energy Consumption by Fuel
 
(PI CHART)
 
 
Source: BP Statistical Review of World Energy, June 2011
 
Coal’s relative abundance, wide distribution, competitive pricing and favorable transportation profile has facilitated its global adoption as a reliable electricity generation fuel. The rapid industrialization of the emerging Asian economies, particularly China and India, are supporting forecasts for significant increases in seaborne thermal coal trade. In 2010, Asia accounted for 66% of world thermal coal imports.


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The Australian Bureau of Agricultural and Resource Economics and Sciences (ABARES) projects world thermal coal trade will grow by 4% annually to 1.1 billion tons in 2016, with Asia accounting for more than 717 million tons of import demand, up from 562 million tons in 2010.
 
In the Atlantic thermal coal market, European Union and other European coal imports are projected to rise from 207 million tons in 2010 to 246 million tons by 2016.
 
We believe the projected robust growth in global thermal coal trade to satisfy growing demand for electricity generation will create substantial opportunities for U.S. coal producers with competitive transportation advantages to profitably export thermal coal.
 
The Illinois Basin coal production region is strategically well positioned with access to the Green, Ohio and Mississippi River systems to deliver coal to New Orleans or Port of Mobile coal export terminals for delivery of coal to growing Atlantic and Pacific import coal consumers.
 
Costs and Pricing Trends
 
Coal prices are influenced by a number of factors and vary materially by region. As a result of these regional characteristics, prices of coal by product type within a given major coal producing region tend to be relatively consistent with each other. The price of coal within a region is influenced by market conditions, coal quality, transportation costs involved in moving coal from the mine to the point of use and mine operating costs. For example, higher carbon and lower ash content generally result in higher prices, and higher sulfur and higher ash content generally result in lower prices within a given geographic region.
 
The cost of coal at the mine is also influenced by geologic characteristics such as seam thickness, overburden ratios and depth of underground reserves. It is generally cheaper to mine coal seams that are thick and located close to the surface than to mine thin underground seams. Within a particular geographic region, underground mining is generally more expensive than surface mining. This is due to typically higher capital costs, including costs for construction of extensive ventilation systems, and higher per unit labor costs arising from lower productivity associated with underground mining.
 
During the past decade, the price of coal has fluctuated like any commodity as a result of changes in supply and demand. For example, when coal supplies declined from 2003 to part of 2006 and subsequently for a short time in 2007 and 2008, the prices for coal reached record highs in the United States. The increased worldwide demand for coal is being driven by higher prices for oil, together with overseas economic expansion in countries such as China and India who rely heavily on coal-fired electricity generation. At the same time, infrastructure, weather-related production interruptions and supply restrictions on exports from China and Indonesia have contributed to a tightening of worldwide thermal coal supply, affecting global prices of