10-K
Table of Contents

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

 

(Mark One)      
þ   

ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

  
  

For the fiscal year ended December 31, 2012

 

OR

  
¨   

TRANSITION REPORT PURSUANT TO SECTIONS 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

  
   For the transition period from             to                

Commission File No. 001-03262

COMSTOCK RESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

NEVADA   94-1667468

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification Number)

5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034 (Address of principal executive offices including zip code)

(972) 668-8800

(Registrant’s telephone number and area code)

Securities registered pursuant to Section 12(b) of the Act:

 

Common Stock, $.50 Par Value   New York Stock Exchange
(Title of class)   (Name of exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  þ    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  ¨    No  þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  þ    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  þ    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     þ

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  þ   Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨
       (Do not check if smaller reporting company)   

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).    Yes  ¨     No  þ

As of February 28, 2013, there were 48,303,517 shares of common stock outstanding.

The aggregate market value of the common stock held by non-affiliates of the registrant, based on the closing price of common stock on the New York Stock Exchange on June 30, 2012 (the last business day of the registrant’s most recently completed second fiscal quarter), was $734.6 million.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Definitive Proxy Statement for the 2012 Annual Meeting of Stockholders

are incorporated by reference into Part III of this report.

 

 

 


Table of Contents

COMSTOCK RESOURCES, INC.

ANNUAL REPORT ON FORM 10-K

For the Fiscal Year Ended December 31, 2012

CONTENTS

 

Item

       Page  
  Part I   
  Cautionary Note Regarding Forward-Looking Statements      2   
  Definitions      3   

1. and 2.

  Business and Properties      6   

1A.

  Risk Factors      31   

1B.

  Unresolved Staff Comments      41   

3.

  Legal Proceedings      41   

4.

  Mine Safety Disclosures      41   
  Part II   

5.

  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities      42   

6.

  Selected Financial Data      43   

7.

  Management’s Discussion and Analysis of Financial Condition and Results of Operations      44   

7A.

  Quantitative and Qualitative Disclosures About Market Risk      54   

8.

  Financial Statements and Supplementary Data      54   

9.

  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      55   

9A.

  Controls and Procedures      55   

9B.

  Other Information      59   
  Part III   

10.

  Directors, Executive Officers and Corporate Governance      59   

11.

  Executive Compensation      59   

12.

  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      59   

13.

  Certain Relationships and Related Transactions, and Directors Independence      60   

14.

  Principal Accountant Fees and Services      60   
  Part IV   

15.

  Exhibits and Financial Statement Schedules      60   

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information contained in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are identified by their use of terms such as “expect,” “estimate,” “anticipate,” “project,” “plan,” “intend,” “believe” and similar terms. All statements, other than statements of historical facts, included in this report, are forward-looking statements, including statements mentioned under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” regarding:

 

   

amount and timing of future production of oil and natural gas;

   

the availability of exploration and development opportunities;

   

amount, nature and timing of capital expenditures;

   

the number of anticipated wells to be drilled after the date hereof;

   

our financial or operating results;

   

our cash flow and anticipated liquidity;

   

operating costs including lease operating expenses, administrative costs and other expenses;

   

finding and development costs;

   

our business strategy; and

   

other plans and objectives for future operations.

Any or all of our forward-looking statements in this report may turn out to be incorrect. They can be affected by a number of factors, including, among others:

 

   

the risks described in “Risk Factors” and elsewhere in this report;

   

the volatility of prices and supply of, and demand for, oil and natural gas;

   

the timing and success of our drilling activities;

   

the numerous uncertainties inherent in estimating quantities of oil and natural gas reserves and actual future production rates and associated costs;

   

our ability to successfully identify, execute or effectively integrate future acquisitions;

   

the usual hazards associated with the oil and natural gas industry, including fires, well blowouts, pipe failure, spills, explosions and other unforeseen hazards;

   

our ability to effectively market our oil and natural gas;

   

the availability of rigs, equipment, supplies and personnel;

   

our ability to discover or acquire additional reserves;

   

our ability to satisfy future capital requirements;

   

changes in regulatory requirements;

   

general economic conditions, status of the financial markets and competitive conditions;

   

our ability to retain key members of our senior management and key employees; and

   

hostilities in the Middle East and other sustained military campaigns and acts of terrorism or sabotage that impact the supply of crude oil and natural gas.

 

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DEFINITIONS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report. Natural gas equivalents and crude oil equivalents are determined using the ratio of six Mcf to one barrel. All references to “us,” “our,” “we” or “Comstock” mean the registrant, Comstock Resources, Inc. and where applicable, its consolidated subsidiaries.

“Bbl” means a barrel of U.S. 42 gallons of oil.

“Bcf” means one billion cubic feet of natural gas.

“Bcfe” means one billion cubic feet of natural gas equivalent.

“BOE” means one barrel of oil equivalent.

“Btu” means British thermal unit, which is the quantity of heat required to raise the temperature of one pound of water from 58.5 to 59.5 degrees Fahrenheit.

“Completion” means the installation of permanent equipment for the production of oil or gas.

“Condensate” means a hydrocarbon mixture that becomes liquid and separates from natural gas when the gas is produced and is similar to crude oil.

“Development well” means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole” means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Exploratory well” means a well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new productive reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

“GAAP” means generally accepted accounting principles in the United States of America.

“Gross” when used with respect to acres or wells, production or reserves refers to the total acres or wells in which we or another specified person has a working interest.

“MBbls” means one thousand barrels of oil.

“MBbls/d” means one thousand barrels of oil per day.

“Mcf” means one thousand cubic feet of natural gas.

“Mcfe” means one thousand cubic feet of natural gas equivalent.

“MMBbls” means one million barrels of oil.

“MMBOE” means one million barrels of oil equivalent.

“MMBtu” means one million British thermal units.

 

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“MMcf” means one million cubic feet of natural gas.

“MMcf/d” means one million cubic feet of natural gas per day.

“MMcfe/d” means one million cubic feet of natural gas equivalent per day.

“MMcfe” means one million cubic feet of natural gas equivalent.

“Net” when used with respect to acres or wells, refers to gross acres of wells multiplied, in each case, by the percentage working interest owned by us.

“Net production” means production we own less royalties and production due others.

“Oil” means crude oil or condensate.

“Operator” means the individual or company responsible for the exploration, development, and production of an oil or gas well or lease.

“PV 10 Value” means the present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with the Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. This amount is the same as the standardized measure of discounted future net cash flows related to proved oil and natural gas reserves except that it is determined without deducting future income taxes. Although PV 10 Value is not a financial measure calculated in accordance with GAAP, management believes that the presentation of PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and gas properties. Because many factors that are unique to any given company affect the amount of estimated future income taxes, the use of a pre-tax measure is helpful to investors when comparing companies in our industry.

“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

“Proved developed non-producing” means reserves (i) expected to be recovered from zones capable of producing but which are shut-in because no market outlet exists at the present time or whose date of connection to a pipeline is uncertain or (ii) currently behind the pipe in existing wells, which are considered proved by virtue of successful testing or production of offsetting wells.

“Proved developed producing” means reserves expected to be recovered from currently producing zones under continuation of present operating methods. This category may also include recently completed shut-in gas wells scheduled for connection to a pipeline in the near future.

“Proved reserves” means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future

 

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years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

“Proved undeveloped reserves” means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances are estimates for proved undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

“Recompletion” means the completion for production of an existing well bore in another formation from which the well has been previously completed.

“Reserve life” means the calculation derived by dividing year-end reserves by total production in that year.

“Reserve replacement” means the calculation derived by dividing additions to reserves from acquisitions, extensions, discoveries and revisions of previous estimates in a year by total production in that year.

“Royalty” means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

“3-D seismic” means an advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

“Tcfe” means one trillion cubic feet of natural gas equivalent.

“Working interest” means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100% working interest in a lease burdened only by a landowner’s royalty of 12.5% would be required to pay 100% of the costs of a well but would be entitled to retain 87.5% of the production.

“Workover” means operations on a producing well to restore or increase production.

 

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PART I

 

ITEMS 1. and 2.    BUSINESS AND PROPERTIES

We are a Nevada corporation engaged in the acquisition, development, production and exploration of oil and natural gas. Our common stock is listed and traded on the New York Stock Exchange.

Our oil and gas operations are concentrated in East Texas/North Louisiana, South Texas and West Texas. Our oil and natural gas properties are estimated to have proved reserves of 711.9 Bcfe with an estimated PV 10 Value of $1.0 billion as of December 31, 2012 and a standardized measure of discounted future net cash flows of $0.8 billion. Our consolidated proved oil and natural gas reserve base is 67% natural gas and 33% oil. Our proved reserves are 62% developed on a Bcfe basis as of December 31, 2012.

Our proved reserves at December 31, 2012 and our 2012 average daily production are summarized below:

 

    Reserves at December 31, 2012     2012 Average Daily Production  
    Oil
(MMBbls)
        Natural    
Gas
(Bcf)
    Total
     (Bcfe)    
    % of
    Total    
    Oil
  (MBbls/d)  
    Natural
Gas
(MMcf/d)
    Total
(MMcfe/d)
    % of
    Total    
 

East Texas / North Louisiana

    0.4        339.4        341.9        48.0     0.2        194.2        195.6        74.3

South Texas

    18.4        86.2        196.5        27.6     4.6        23.6        51.1        19.4

West Texas

    20.3        39.2        161.1        22.6     1.4        2.0        10.5        4.0

Other Regions

    0.1        11.8        12.4        1.8     0.1        5.6        6.1        2.3
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    39.2        476.6        711.9        100.0     6.3        225.4        263.3        100.0
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Strengths

High Quality Properties.    Our operations are focused in three primary operating areas: East Texas/North Louisiana, South Texas and West Texas. Our properties have an average reserve life of approximately 7.4 years and have extensive development and exploration potential. In response to the continuing low natural gas price environment, we have focused our drilling activity primarily on oil projects. Our two primary properties that provide opportunities to increase our oil production and reserves are our South Texas Eagle Ford shale properties and our Wolfbone field in West Texas. We have 34,727 acres (27,689 net to us) in the Eagle Ford shale and we have 88,666 acres (54,355 net to us) in West Texas prospective in the Bone Spring and Wolfcamp shales. Our properties in the East Texas/North Louisiana region, including 93,620 acres (80,046 net to us) in the Haynesville or Bossier shales, are primarily prospective for natural gas.

Successful Exploration and Development Program.    In 2012 we spent $524.9 million, net of reimbursed costs from our joint venture partner, on exploration and development activities. We drilled 85 wells (54.2 net to us) in 2012 at a cost of $415.1 million and we spent $70.9 million to complete 20 wells (13.6 net to us) that were drilled in 2011. We also spent $35.1 million in 2012 to acquire additional leasehold, $0.1 million to acquire seismic data and $3.7 million for recompletions, workovers, abandonment and production facilities. 80% of our 2012 capital expenditures were directed towards oil projects. Our drilling activities in 2012 added 22.5 MMBOE to our proved reserves and increased our oil production by 175% from 2011.

Efficient Operator.    We operated 90% of our proved oil and natural gas reserve base as of December 31, 2012. As operator we are better able to control operating costs, the timing and plans for

 

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future development, the level of drilling and lifting costs and the marketing of production. As an operator, we receive reimbursements for overhead from other working interest owners, which reduces our general and administrative expenses.

Successful Acquisitions.    We have had significant growth over the years as a result of our acquisition activity. We apply strict economic and reserve risk criteria in evaluating acquisitions. Over the last twenty years, we have added 1.1 Tcfe of proved oil and natural gas reserves from 38 acquisitions at an average cost of $1.17 per Mcfe. Our application of strict economic and reserve risk criteria have enabled us to successfully evaluate and integrate acquisitions.

Business Strategy

Pursue Exploration Opportunities.    We conduct exploration activities to grow our reserve base and to replace our production each year. During 2012 we refocused our efforts on prospects with potential for oil development, and we have limited our drilling on our natural gas properties due to the decline in natural gas prices.

From 2010 through 2012 we spent approximately $155.2 million to acquire 34,727 acres (27,689 net to us) in South Texas, which we believe to be prospective for oil in the Eagle Ford shale formation. In 2012, we spent approximately $201.7 million to drill 30 wells (20.5 net to us) on our Eagle Ford shale properties. In 2012 we entered into a joint venture arrangement to allow us to accelerate the development of our acreage. Our joint venture partner participates for a one-third interest in the wells that we drill in exchange for paying $25,000 per net acre that is earned by their participation. In 2012, our Eagle Ford shale drilling program added 13.2 MMBOE to our proved reserves. In 2013 we have budgeted to spend $219.0 million, net of reimbursements from our joint venture partner, to drill 42 wells (27.3 net to us) on our Eagle Ford shale properties and to complete six wells (3.8 net to us) that were drilled in 2012.

We have spent approximately $340.0 million to acquire 68,764 acres (41,071 net to us) in Reeves County in West Texas, which we believe to be prospective for oil in the Bone Spring and Wolfcamp shales in the Delaware Basin. During 2012 we spent $183.4 million and drilled 48 wells (30.5 net to us) in West Texas. Our drilling program added 6.9 MMBOE to our reserves in 2012. In 2013 we have budgeted $168.9 million to drill 33 wells (27.2 net to us), including eight horizontal Wolfcamp shale wells (7.3 net to us).

We have a significant acreage position of 93,620 acres (80,046 net to us) in East Texas and North Louisiana with Haynesville or Bossier shale natural gas potential but in 2012 we have deferred most of our drilling operations due to the low natural gas price environment. In 2012, we drilled seven Haynesville and Bossier shale horizontal wells (3.2 net to us) which added 14 Bcfe to our proved reserves in 2012. With the low natural gas price outlook in 2013, we continue to defer our natural gas focused drilling. We have budgeted to spend $32.1 million in 2013 to drill ten Haynesville and Bossier shale horizontal wells (3.6 net to us).

Exploit Existing Reserves.    We seek to maximize the value of our oil and gas properties by increasing production and recoverable reserves through development drilling and workover, recompletion and exploitation activities. We utilize advanced industry technology, including 3-D seismic data, horizontal drilling, improved logging tools, and formation stimulation techniques.

Maintain Flexible Capital Expenditure Budget.    The timing of most of our capital expenditures is discretionary because we have not made any significant long-term capital expenditure commitments except for contracted drilling and completion services. We operate most of the drilling projects in which we participate. Consequently, we have a significant degree of flexibility to adjust the level of such

 

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expenditures according to market conditions. We have budgeted to spend approximately $420.0 million in 2013 on our development and exploration projects and $25.0 million for lease acquisition activity.

Acquire High Quality Properties at Attractive Costs.    Historically, we have had a successful track record of increasing our oil and natural gas reserves through opportunistic acquisitions. Over the last twenty years, we have added 1.1 Tcfe of proved oil and natural gas reserves from 38 acquisitions at a total cost of $1.3 billion, or $1.17 per Mcfe. The acquisitions were acquired at an average of 67% of their PV 10 Value in the year the acquisitions were completed. In evaluating acquisitions, we apply strict economic and reserve risk criteria. We target properties in our core operating areas with established production and low operating costs that also have potential opportunities to increase production and reserves through exploration and exploitation activities. We also evaluate our existing properties and consider divesting of non-strategic assets when market conditions are favorable.

Primary Operating Areas

The following table summarizes the estimated proved oil and natural gas reserves for our fifteen largest field areas as of December 31, 2012:

 

     Oil
(MBbls)
     Natural
Gas
(MMcf)
     Total
(MMcfe)(1)
         %         PV 10  Value(2)
(000’s)
        %      

East Texas / North Louisiana:

               

Logansport

     15         212,172         212,263         29.8   $ 123,779        12.1

Toledo Bend

             44,965         44,965         6.3     27,810        2.7

Beckville

     125         31,130         31,880         4.5     28,357        2.8

Waskom

     98         14,207         14,798         2.1     14,365        1.4

Blocker

     46         10,901         11,175         1.6     9,351        0.9

Mansfield

             8,614         8,614         1.2     4,990        0.5

Darco

     12         3,845         3,919         0.6     2,136        0.2

Douglass

             2,995         2,995         0.4     976        0.1

Other

     117         10,560         11,256         1.5     9,240        0.8
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 
     413         339,389         341,865         48.0     221,004        21.5
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

South Texas:

               

Eagleville

     18,281         14,051         123,739         17.4     532,714        51.9

Fandango

             37,274         37,274         5.2     19,782        1.9

Rosita

             16,295         16,296         2.3     6,601        0.6

Javelina

     39         7,809         8,046         1.1     9,759        1.0

Las Hermanitas

             4,482         4,483         0.6     2,300        0.2

Other

     61         6,335         6,696         1.0     6,768        0.7
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 
     18,381         86,246         196,534         27.6     577,924        56.3
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

West Texas:

               

Wolfbone

     20,320         39,155         161,073         22.6     212,186        20.7
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 
     20,320         39,155         161,073         22.6     212,186        20.7
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Other:

               

San Juan Basin

     12         3,311         3,381         0.5     4,107        0.4

Other

     93         8,499         9,064         1.3     11,309        1.1
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 
     105         11,810         12,445         1.8     15,416        1.5
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total

     39,219         476,600         711,917         100.0     1,026,530        100.0
  

 

 

    

 

 

    

 

 

    

 

 

     

 

 

 

Discounted Future Income Taxes

                (242,313  
             

 

 

   

Standardized Measure of Discounted Future Cash Flows

              $ 784,217     
             

 

 

   

 

 

 

  (1) Oil is converted to natural gas equivalents by using a conversion factor of one barrel of oil for six Mcf of natural gas.

 

  (2) The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although it is a non-GAAP measure, we believe that the presentation of the PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and gas properties. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.

 

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East Texas/North Louisiana Region

Approximately 48% or 341.9 Bcfe of our proved reserves are located in East Texas and North Louisiana where we own interests in 958 producing wells (585.8 net to us) in 28 field areas. We operate 664 of these wells. The largest of our fields in this region are the Logansport, Toledo Bend, Beckville, Waskom, Blocker, Mansfield, Darco and Douglass fields. Production from this region averaged 194 MMcf of natural gas per day and 220 barrels of oil per day during 2012 or 196 MMcfe per day. Most of the reserves in this area produce from the upper Jurassic aged Haynesville or Bossier shale or Cotton Valley formations and the Cretaceous aged Travis Peak/Hosston formation. In 2012, we spent $101.1 million drilling seven wells (3.2 net to us) and completing 16 wells (10.4 net to us) that were drilled in 2011. We also spent $8.2 million on leasehold costs and $1.7 million on workovers and recompletions in this region. All seven of the wells we drilled in 2012 were horizontal wells that targeted the Haynesville or Bossier shales. We plan to spend approximately $32.1 million in 2013 in this region to drill ten (3.6 net to us) horizontal wells targeting the Haynesville or Bossier shales. These wells are required to retain our interest in certain undeveloped leases.

Logansport

The Logansport field located in DeSoto Parish, Louisiana primarily produces from the Haynesville and Bossier shale formations at a depth of 11,100 to 11,500 feet and from multiple sands in the Cotton Valley and Hosston formations at an average depth of 8,000 feet. Our proved reserves of 212.3 Bcfe in the Logansport field represent approximately 30% of our proved reserves. We own interests in 254 wells (163.2 net to us) and operate 180 of these wells in this field. During December 2012 net daily production attributable to our interest from this field averaged 94 MMcf of natural gas and 20 barrels of oil. In 2012 we completed ten Haynesville or Bossier shale horizontal wells (8.2 net to us) in Logansport that were drilled in 2011. In 2013 we plan to drill three horizontal Haynesville or Bossier shale wells (0.6 net to us) in our Logansport field.

Toledo Bend

The Toledo Bend field in Desoto and Sabine Parishes, Louisiana was discovered in 2008 with our first horizontal Haynesville shale well. Production from the Haynesville shale in the Toledo Bend field ranges from 11,400 to 11,800 feet and from 10,880 to 11,300 feet in the Bossier shale. Our proved reserves of 45 Bcfe in the Toledo Bend field represent approximately 6% of our reserves. We own interests in 72 producing wells (37.3 net to us) and operate 39 of these wells in this field. During 2012 we drilled four Haynesville or Bossier shale horizontal wells (1.3 net to us) at Toledo Bend and we completed six wells (2.1 net to us) that were drilled in 2011. During December 2012, net daily production attributable to our interest from this field averaged 35 MMcf of natural gas. In 2013, we plan to drill five horizontal Haynesville or Bossier shale wells (2.6 net to us) in this field.

Beckville

The Beckville field, located in Panola and Rusk Counties, Texas, has estimated proved reserves of 31.9 Bcfe which represents approximately 5% of our proved reserves. We operate 192 wells in this field and own interests in 81 additional wells for a total of 273 wells (160.4 net to us). During December 2012, production attributable to our interest from this field averaged 8 MMcf of natural gas per day and 40 barrels of oil per day. The Beckville field produces primarily from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet. The field is also prospective for future Haynesville shale development.

 

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Waskom

The Waskom field, located in Harrison and Panola Counties in Texas, represents approximately 2% (14.8 Bcfe) of our proved reserves as of December 31, 2012. We own interests in 63 wells in this field (40.5 net to us) and operate 48 wells in this field. During December 2012, net daily production attributable to our interest averaged 5 MMcf of natural gas and 20 barrels of oil from this field. The Waskom field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet and from the Haynesville shale formation at depths of 10,800 to 10,900 feet.

Blocker

Our proved reserves of 11.2 Bcfe in the Blocker field located in Harrison County, Texas represent approximately 2% of our proved reserves. We own interests in 77 wells (71.0 net to us) and operate 71 of these wells. During December 2012, net daily production attributable to our interest from this field averaged 4 MMcf of natural gas and 22 barrels of oil. Most of this production is from the Cotton Valley formation between 8,600 and 10,150 feet and the Haynesville shale formation between 11,100 and 11,450 feet.

Mansfield

The Mansfield field is located in DeSoto Parish Louisiana and produces from the Haynesville shale between 12,250 and 12,350 feet. We own interests in 17 wells (4.6 net to us) and operate four of these wells. Our proved reserves in this field of 8.6 Bcfe represent approximately 1% of our total reserves. During December 2012, net daily production attributable to our interest for this field averaged 4 MMcf of natural gas. In 2013, we plan to drill two (0.4 net to us) horizontal Haynesville shale wells in this field.

Darco

The Darco field is located in Harrison County, Texas and produces from the Cotton Valley formation at depths from approximately 9,800 to 10,200 feet. Our proved reserves of 3.9 Bcfe in the Darco field represent approximately 1% of our reserves. We own interests in 23 wells (18 net to us) and operate all of these wells. During December 2012, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas.

Douglass

The Douglass field is located in Nacogdoches County, Texas and is productive from stratigraphically trapped reservoirs in the Pettet Lime and Travis Peak formations. These reservoirs are found at depths from 9,200 to 10,300 feet. Our proved reserves of 3.0 Bcfe in the Douglass field represent less than 1% of our reserves. We own interests in 40 wells (25.8 net to us) and operate 33 of these wells. During December 2012, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas.

South Texas Region

Approximately 28%, or 32.8 MMBOE (196.5 Bcfe,) of our proved reserves are located in South Texas, where we own interests in 191 producing wells (116.6 net to us). We own interests in 16 field areas in the region, the largest of which are the Eagleville, Fandango, Rosita, Javelina and Las Hermanitas fields. Net daily production rates from this region averaged 4,587 barrels of oil and 24 MMcf

 

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of natural gas during 2012 or 8,521 BOE per day. We spent $202.9 million in 2012, net of cost recoveries from our joint venture partner, to drill 30 (20.5 net to us) Eagle Ford shale wells and for other development activity. We also spent $7.7 million in this region in 2012 to acquire acreage. In 2013 we plan to spend approximately $219.0 million to drill 42 horizontal wells (27.3 net to us) and to complete six Eagle Ford shale wells (3.8 net to us) that were drilled in 2012.

Eagleville

We have 34,727 acres (27,689 net to us) in McMullen, La Salle, Atascosa, Wilson and Karnes Counties which are prospective for Eagle Ford shale development in South Texas. The Eagle Ford Shale is found between 7,500 feet and 11,500 feet across our acreage position. During December 2012 we had 49 wells (40.5 net to us) that were producing a total of 4,023 barrels of oil per day and 2.4 MMcf per day of natural gas net to our interest or 4,418 BOE per day. Our proved reserves in this field are estimated to be 20.6 MMBOE (123.7 Bcfe) (89% oil) and represent 17% of our total proved reserves. All of our planned South Texas drilling activity in 2013 will be in the Eagleville field.

Fandango

We own interests in 20 wells (20.0 net to us) in the Fandango field, located in Zapata County, Texas. We operate all of these wells which produce from the Wilcox formation at depths from approximately 13,000 to 18,000 feet. Our proved reserves of 37.3 Bcfe in this field represent approximately 5% of our total proved reserves. Production from this field averaged 9 MMcf of natural gas per day during December 2012.

Rosita

We own interests in 30 wells (16.2 net to us) in the Rosita field, located in Duval County, Texas. We operate four of these wells which produce from the Wilcox formation at depths from approximately 9,300 to 17,000 feet. Our proved reserves of 16.3 Bcfe in this field represent approximately 2% of our total proved reserves. Production from this field averaged 3 MMcf of natural gas per day during December 2012.

Javelina

We own interests in and operate 18 wells (18.0 net to us) in the Javelina field in Hidalgo County in South Texas. These wells produce primarily from the Vicksburg formation at a depth of approximately 10,900 to 12,500 feet. Proved reserves attributable to our interests in the Javelina field are 8.0 Bcfe, which represents 1% of our total proved reserves. During December 2012, production attributable to our interest from this field averaged 3 MMcf of natural gas per day and 21 barrels of oil per day.

Las Hermanitas

We own interests in and operate 11 natural gas wells (9.0 net to us) in the Las Hermanitas field, located in Duval County, Texas. These wells produce from the Wilcox formation at depths from approximately 11,400 to 11,800 feet. Our proved reserves of 4.5 Bcfe in this field represent approximately 1% of our total proved reserves. During December 2012, net daily production attributable to our interest from this field averaged 2 MMcf of natural gas.

 

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West Texas Region

Wolfbone

We own interests in 68,764 acres (41,071 net to us) in Reeves County in the Delaware Basin in West Texas that are prospective for the Bone Spring formation from depths of 10,000 to 10,300 feet and the Wolfcamp shale formation from depths of 10,300 to 11,500 feet, most of which was acquired by us in 2011. Our proved reserves of 26.8 MMBOE (161.1 Bcfe) in the Wolfbone field are 76% oil and represent 23% of our total proved reserves. Net daily production rates from this region averaged 1,410 barrels of oil and 2 MMcf of natural gas during 2012 or 1,744 BOE per day. During 2012 we spent $183.9 million to drill 48 (30.5 net to us) oil wells and for other development activity. We also spent $19.2 million in this region in 2012 to acquire acreage. In 2013 we have budgeted to spend $168.9 million to drill 33 wells (27.2 net to us) in this region and to complete three wells (1.0 net to us) drilled in 2012.

Other Regions

Approximately 2%, or 12.4 Bcfe, of our proved reserves are in other regions, primarily in New Mexico and the Mid-Continent region. We own interests in 421 producing wells (161.0 net to us) in 20 fields within these regions. The field with the largest proved reserves is our San Juan Basin properties in New Mexico. Net daily production from our other regions during 2012 totaled 6 MMcf of natural gas and 87 barrels of oil or 6 MMcfe per day.

San Juan

Our San Juan Basin properties are located in the west-central portion of the basin in San Juan County, New Mexico. These wells produce from multiple sands of the Cretaceous Dakota formation and the Fruitland Coal seams. The Dakota is generally found at about 6,000 feet with the shallower Fruitland seams encountered at 2,500 to 3,000 feet. Our proved reserves of 3.4 Bcfe in the San Juan field represent less than 1% of our reserves. We own interests in 93 wells (14.1 net to us) in this field. During December 2012, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas and 2 barrels of oil.

Major Property Acquisitions

As a result of our acquisitions, we have added 1.1 Tcfe of proved oil and natural gas reserves since 1991. Our ten largest acquisitions include the following:

Delaware Basin Acquisition.    In December 2011, we acquired certain oil and gas properties from Eagle Oil & Gas Co. and other third parties for $348.7 million. The properties acquired had estimated proved reserves of approximately 151.2 Bcfe and included approximately 65,000 exploratory acres (39,100 net to us).

Shell Wilcox Acquisition.    In December 2007, we completed the acquisition of certain oil and natural gas properties and related assets from SWEPI LP, an affiliate of Shell Oil Company for $160.1 million. The properties acquired had estimated proved reserves of approximately 70.1 Bcfe. Major fields acquired in the acquisition include the Fandango and Rosita fields.

Javelina Acquisition.    In June 2007 we acquired additional working interests in oil and gas properties in the Javelina field in South Texas from Abaco Operating LLC for $31.2 million. The properties acquired had estimated proved reserves of approximately 9.1 Bcfe.

 

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Denali Acquisition.    In September 2006 we acquired proved and unproved oil and gas properties in the Las Hermanitas field in South Texas from Denali Oil & Gas Partners LP and other working interest owners for $67.2 million. The properties acquired had estimated proved reserves of approximately 16.5 Bcfe.

Ensight Acquisition.    In May 2005, we completed the acquisition of certain oil and natural gas properties and related assets from Ensight Energy Partners, L.P., Laurel Production, LLC, Fairfield Midstream Services, LLC and Ensight Energy Management, LLC (collectively, “Ensight”) for $190.9 million. We also purchased additional interests in those properties from other owners for $10.9 million in July 2005. The properties acquired had estimated proved reserves of approximately 121.5 billion cubic feet of natural gas equivalent and included 312 active wells, of which 119 are operated by us. Major fields acquired include the Darco, Douglass, Cadeville, and Laurel fields. We divested of the Laurel field in 2010.

Ovation Energy Acquisition.    In October 2004, we acquired producing oil and gas properties in the East Texas, Arkoma, Anadarko and San Juan basins from Ovation Energy, L.P. for $62.0 million. The properties acquired had estimated proved reserves of approximately 41.0 billion cubic feet of gas equivalent and included 165 active wells, of which 69 were operated by us.

DevX Energy Acquisition.    In December 2001, we completed the acquisition of DevX Energy, Inc. by acquiring 100% of the common stock of DevX for $92.6 million. The total purchase price including debt and other liabilities assumed in the acquisition was $160.8 million. The acquisition included 600 producing wells located onshore primarily in East and South Texas, Kentucky, Oklahoma and Kansas with 1.2 MMBbls of oil reserves and 156.5 Bcf of natural gas reserves at the time of the acquisition.

Bois d’Arc Acquisition.    In December 1997, Comstock acquired working interests in certain producing offshore Louisiana oil and gas properties as well as interests in undeveloped offshore oil and natural gas leases for approximately $200.9 million from Bois d’Arc Resources and certain of its affiliates and working interest partners. We acquired interests in 43 wells (29.6 net to us) and eight separate production complexes located in the Gulf of Mexico offshore of Plaquemines and Terrebonne Parishes, Louisiana. The acquisition included interests in the Louisiana state and federal offshore areas of Main Pass Block 21, Ship Shoal Blocks 66, 67, 68 and 69 and South Pelto Block 1. The net proved reserves acquired in this acquisition were estimated at 14.3 MMBbls of oil and 29.4 Bcf of natural gas. We divested of these offshore properties in 2008.

Black Stone Acquisition.    In May 1996, we acquired 100% of the capital stock of Black Stone Oil Company and interests in producing and undeveloped oil and gas properties located in South Texas for $100.4 million. We acquired interests in 19 wells (7.7 net to us) that were located in the Double A Wells field in Polk County, Texas and we became the operator of most of the wells in the field. The net proved reserves acquired in this acquisition were estimated at 5.9 MMBbls of oil and 100.4 Bcf of natural gas. We divested of these properties in 2012.

Sonat Acquisition.    In July 1995, we purchased interests in certain producing oil and gas properties located in East Texas and North Louisiana from Sonat Inc. for $48.1 million. We acquired interests in 319 producing wells (188.0 net to us). The acquisition included interests in the Logansport, Beckville, Waskom, Hico-Knowles, and Blocker fields. The net proved reserves acquired in this acquisition were estimated at 0.8 MMBbls of oil and 104.7 Bcf of natural gas. We divested of the Hico-Knowles field in 2012.

 

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Oil and Natural Gas Reserves

The following table sets forth our estimated proved oil and natural gas reserves and the PV 10 Value as of December 31, 2012:

 

     Oil
(MBbls)
     Natural
Gas

(MMcf)
     Total
(MMcfe)
     PV 10 Value
(000’s)
 

Proved Developed:

           

Producing

     11,503         367,140         436,157       $ 759,743   

Non-producing

     805         1,635         6,466         37,877   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved Developed

     12,308         368,775         442,623         797,620   

Proved Undeveloped

     26,911         107,825         269,294         228,910   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

     39,219         476,600         711,917         1,026,530   
  

 

 

    

 

 

    

 

 

    

Discounted Future Income Taxes

              (242,313
           

 

 

 

Standardized Measure of Discounted Future Net Cash Flows(1)

            $ 784,217   
           

 

 

 

 

 

  (1) The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10%. Although it is a non-GAAP measure, we believe that the presentation of the PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and gas properties. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.

The following table sets forth our year end reserves as of December 31 for each of the last three fiscal years:

 

     2010      2011      2012  
     Oil
(MBbls)
     Natural Gas
(MMcf)
     Oil
(MBbls)
     Natural Gas
(MMcf)
     Oil
(MBbls)
     Natural Gas
(MMcf)
 

Proved Developed

     2,961         506,809         8,405         550,474         12,308         368,775   

Proved Undeveloped

     1,258         518,824         23,694         568,158         26,911         107,825   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved Reserves

       4,219         1,025,633         32,099         1,118,632         39,219         476,600   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Proved reserves that are attributable to existing producing wells are primarily determined using decline curve analysis and rate transient analysis, which incorporates the principles of hydrocarbon flow. Proved reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. Technologies relied on to establish reasonable certainty of economic producibility include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available production data, seismic data and well test data.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

 

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The average prices that we realized from sales of oil and natural gas, excluding the effect of hedging, and lifting costs including severance and ad valorem taxes and transportation costs, for each of the last three fiscal years were as follows:

 

     Year Ended December 31,  
     2010      2011      2012  

Oil Price — $/Bbl

   $ 68.35       $ 95.73       $ 96.95   

Natural Gas Price — $/Mcf

   $ 4.35       $ 3.91       $ 2.52   

Lifting costs — $/Mcfe

   $ 1.10       $ 0.82       $ 1.06   

Prices used in determining quantities of oil and natural gas reserves and future cash inflows from oil and natural gas reserves represent prices received at the point of sale. These prices have been adjusted from posted prices for both location and quality differences. The oil and natural gas prices used for reserves estimation were as follows:

 

Year

   Oil Price
(per  Bbl)
     Natural
Gas Price

(per Mcf)
 

2010

   $ 76.31       $ 4.16   

2011

   $ 92.93       $ 4.18   

2012

   $ 94.61       $ 2.84   

Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered, and they are scheduled to be drilled within five years of their initial inclusion as proved reserves, unless specific circumstances justify a longer time. In connection with estimating proved undeveloped reserves for our December 31, 2012 reserve report, reserves on undrilled acreage were limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled. Using empirical evidence, we utilize control points and sample sizes to show continuity in the reservoir.

The following table presents the changes in our estimated proved undeveloped oil and natural gas reserves for the years ended December 31, 2010, 2011 and 2012:

 

     Proved Undeveloped Reserves  
     2010     2011     2012  
     Oil
(MBbls)
    Natural Gas
(MMcf)
    Oil
(MBbls)
     Natural Gas
(MMcf)
    Oil
(MBbls)
    Natural Gas
(MMcf)
 

Beginning Balance

     2,320        315,287        1,258         518,824        23,694        568,158   

Sales and Disposals

     (1,996     (2,378                    (5,698     (21,459

Acquisitions

                   16,959         45,792                 

Extension & Discoveries

     1,012        241,160        5,151         66,978        10,526        11,778   

Conversions from undeveloped to developed

            (8,825             (39,761     (1,597     (1,466

Price, Performance and Other Revisions

     (78     (26,420     326         (23,675     (14     (449,186
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Total Change

     (1,062     203,537        22,436         49,334        3,217        (460,333
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Ending Balance

     1,258        518,824        23,694         568,158        26,911        107,825   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

 

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The timing, by year, when our proved undeveloped reserve quantities were estimated to be converted to proved developed reserves is as follows:

 

     Proved Undeveloped Reserves  
     2010      2011      2012  

Year ended December 31,

   Oil
(MBbls)
     Natural Gas
(MMcf)
     Oil
(MBbls)
     Natural Gas
(MMcf)
     Oil
(MBbls)
     Natural Gas
(MMcf)
 

2011

     527         107,729                                   

2012

     426         163,984         8,250         51,034                   

2013

     305         138,831         4,909         264,497         4,402         16,220   

2014

             93,547         9,329         215,756         4,545         34,695   

2015

             14,733         925         36,311         4,769         25,472   

2016

                     201         402         7,708         22,411   

2017

                     80         158         5,487         9,027   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     1,258         518,824         23,694         568,158         26,911         107,825   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Our oil proved undeveloped reserves increased by 3.2 MMBbls during 2012. This increase was primarily due to our drilling program which added 8.1 MMBbls in the Eagle Ford shale and 2.4 MMBbls in West Texas. We also sold 5.7 million barrels of proved undeveloped oil reserves, and converted 1.6 million barrels to developed in 2012.

Our natural gas proved undeveloped reserves decreased by 460 Bcf at December 31, 2012 as compared with December 31, 2011. This decrease was primarily related to the decline in natural gas prices, which caused approximately 465 Bcf of our natural gas proved undeveloped reserves to become uneconomic under the natural gas price used to determine proved reserves in 2012. We also sold 22 Bcf of natural gas proved undeveloped reserves, added 11 Bcf of natural gas proved undeveloped reserves from our drilling program, and had other revisions of 16 Bcf. Included in the 465 Bcf of reserves reductions associated with downward price revisions were 330 Bcf of proved undeveloped natural gas reserves that, as of December 31, 2011 had positive undiscounted future cash flows but had a rate of return that was less than 10%. These reserves became uneconomic due to the lower natural gas prices used to determine our 2012 year end reserve estimates.

As of December 31, 2012, our proved undeveloped reserves included 26.9 MMBbls of oil and 107.8 Bcf of natural gas, for a total of 269.3 Bcfe of undeveloped reserves. Approximately 16.4 MMBbls of oil and 33 Bcf of natural gas of our proved undeveloped reserves at December 31, 2012 were associated with the future development of our West Texas properties that we acquired in December 2011 and an additional 10.5 MMBbls of oil and 7 Bcf of natural gas were associated with our Eagle Ford shale properties in South Texas. The proved undeveloped reserves associated with our Haynesville or Bossier shale properties represented approximately 55 Bcf of our natural gas proved undeveloped reserves at December 31, 2012. The remaining proved undeveloped reserves are primarily associated with developing reserves in our Cotton Valley and Hosston sand reservoirs in East Texas/North Louisiana and the Wilcox and Vicksburg reservoirs in South Texas. In 2012, we focused on drilling oil properties due to the weak natural gas prices. Seven of the Eagle Ford shale wells and four of the Wolfbone shale oil wells we drilled in 2012 resulted in conversions of proved undeveloped reserves to proved developed producing reserves at December 31, 2012. Undeveloped natural gas reserves originally expected to be converted to developed reserves in 2012 were removed from our proved reserves due to the low natural gas prices during 2012.

 

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Our oil proved undeveloped reserves increased by 22.4 MMBbls during 2011. This increase was primarily due to our acquisition of proved undeveloped reserves in West Texas of 17.0 MMBbls, proved undeveloped reserves additions of 4.7 MMBbls from our Eagle Ford shale properties and 0.7 MMBbls of oil additions and revisions on our other properties. Our natural gas proved undeveloped reserves increased by 49 Bcf during 2011. This increase was primarily related to our successful Haynesville and Bossier shale drilling program which added 44 Bcf of natural gas reserves, our acquisition in West Texas which added 34 Bcf and we had other additions of approximately 36 Bcf. Our proved undeveloped natural gas reserves additions were partially offset by conversions to proved developed reserves of approximately 40 Bcf during 2011 and other downward revisions to previous estimates of approximately 23 Bcf.

As of December 31, 2011, our proved undeveloped reserves included 23.7 MMBbls of oil and 568 Bcf of natural gas, for a total of 710 Bcfe of undeveloped reserves. Approximately 17.0 MMBbls of oil and 34 Bcf of natural gas of our proved undeveloped reserves at December 31, 2011 were associated with the future development of our West Texas properties that we acquired in December 2011 and an additional 6.0 MMBbls of oil and 5 Bcf of natural gas were associated with our Eagle Ford shale properties in South Texas. The proved undeveloped natural gas reserves associated with our Haynesville or Bossier shale properties represented approximately 425 Bcf of our total natural gas proved undeveloped reserves at December 31, 2011. The remaining proved undeveloped reserves are primarily associated with developing reserves in our Cotton Valley and Hosston sand reservoirs in East Texas/North Louisiana and our Wilcox and Vicksburg reservoirs in South Texas. During the year ended December 31, 2011, the price of oil increased significantly, and the value of oil relative to natural gas on a heating equivalent basis widened to historic levels. This, coupled with a growing over-supply of natural gas in the United States, caused us to change our strategic focus towards oil and away from natural gas. As a result, our drilling program during 2011, which was initially focused on our Haynesville and Bossier shale reserves, was refocused during the year towards our oil prone properties in the Eagle Ford shale in South Texas. Eleven of the Haynesville shale wells we drilled in 2011 resulted in conversions of proved undeveloped reserves to proved developed producing reserves at the end of 2011. To better position the company for future growth of oil production, in late 2011 we acquired a substantial acreage position in West Texas which is prospective for oil. A portion of this acquisition was determined to contain proved undeveloped reserves.

Our estimates of oil and natural gas reserves at December 31, 2012 include 80.6 Bcfe related to undrilled wells that have positive undiscounted future cash flows but which, based upon oil and natural gas prices that we use to prepare the proved reserve estimates, have a rate of return that is less than the 10% discount rate used in the Standardized Measure of Discounted Future Cash Flows attributable to the proved reserve estimates. We intend to drill the proved undeveloped wells in the time frame reflected in the estimates of proved oil and natural gas reserves as of December 31, 2012 based upon the oil and natural gas prices that we used to prepare the reserve estimates. We anticipate drilling such proved undeveloped locations based on our current development plans for our properties. Certain of these wells may be drilled to retain leasehold interests or to properly manage reservoir performance. To the extent that actual oil or natural gas prices are substantially weaker, we may have to modify our development plans or we may not fully recover our investment in drilling these wells from future cash flows.

 

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Table of Contents

The following table presents the estimated timing of our estimated future development capital costs to be incurred for the years ended December 31, 2010, 2011 and 2012:

 

     Future Development Costs
Total Proved Undeveloped Reserves
 
Year ended December 31,    2010      2011      2012  
     (in millions)  

2011

   $ 237.3       $       $   

2012

     381.0         395.4           

2013

     299.6         734.4         122.5   

2014

     199.0         742.4         111.5   

2015

     28.4         117.9         325.8   

2016

             9.4         275.3   

2017

             4.2         233.1   
  

 

 

    

 

 

    

 

 

 

Total

   $ 1,145.3       $ 2,003.7       $ 1,068.2   
  

 

 

    

 

 

    

 

 

 

The following table presents the changes in our estimated future development costs for the years ended December 31, 2011 and 2012:

 

     Future Development Costs — Proved Undeveloped Reserves  
     Haynesville
Shale
    Eagle Ford
Shale
    West Texas
Properties
    All Other
Properties
    Total  
     (in millions)  

Total as of December 31, 2010

   $ 698.9      $ 49.0      $      $ 397.4      $ 1,145.3   

Development Costs Incurred

     (56.3                          (56.3

Additions and Revisions

     243.5        169.0        653.5        (151.3     914.7   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Changes

     187.2        169.0        653.5        (151.3     858.4   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total as of December 31, 2011

     886.1        218.0        653.5        246.1        2,003.7   

Development Costs Incurred

     (24.7     (43.4     (19.2            (87.3

Sales and Disposals

                          (48.1     (48.1

Additions and Revisions

     (777.5     174.2        (19.5     (177.3     (800.1
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Changes

     (802.2     130.8        (38.7     (225.4     (935.5
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total as of December 31, 2012

   $ 83.9      $ 348.8      $ 614.8      $ 20.7      $ 1,068.2   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Our estimated future capital costs to develop proved undeveloped reserves as of December 31, 2012 of $1.1 billion decreased by $0.9 billion from our estimated future capital costs of $2.0 billion as of December 31, 2011. During 2012 we incurred approximately $87.3 million to develop proved undeveloped reserves, primarily in our Eagle Ford shale and West Texas properties. Our oil focused future capital expenditures increased by $155.0 million and our natural gas focused capital expenditures decreased by $955.0 million. Approximately $749.0 million of the reduction in our estimated future development costs in 2012 was associated with wells that, as of December 31, 2011, had positive undiscounted cash flows but had a rate of return of less than 10%.

Our estimated future capital costs to develop proved undeveloped reserves as of December 31, 2011 of $2.0 billion increased by $858.0 million from our estimated future capital costs of $1.1 billion as of December 31, 2010. During 2011, we incurred approximately $56.3 million to develop proved undeveloped reserves in our Haynesville shale properties. Due to the success of our oil focused drilling

 

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programs, we increased our proved undeveloped reserve estimates in the Eagle Ford shale and we acquired properties in West Texas with significant potential for oil during 2011. During 2011 our oil focused future capital expenditures increased by $169.0 million in the Eagle Ford shale and $654.0 million in West Texas. Our future capital expenditures in the Haynesville and Bossier shales increased by $244.0 million during 2011 reflecting our 2011 drilling success on these properties, while we further reduced our forecast of capital expenditures on our remaining conventional natural gas undeveloped reserves by $151.0 million during 2011.

The estimates of our oil and natural gas reserves were determined by Lee Keeling and Associates, Inc. (“Lee Keeling”), an independent petroleum engineering firm. Lee Keeling has been providing consulting engineering and geological services for over fifty years. Lee Keeling’s professional staff is comprised of qualified petroleum engineers who are experienced in all productive areas of the United States. The technical person responsible for review of our reserve estimates at Lee Keeling meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Lee Keeling does not own any interests in our properties and is not employed on a contingent fee basis.

We have established, and maintain, internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations promulgated by the SEC. These internal controls include documented process workflows, employing qualified professional engineering and geological personnel, and on-going education for personnel involved in our reserves estimation process. Our internal audit function routinely tests our processes and controls. Inputs to our reserves estimation process, which we provide to Lee Keeling for use in their reserves evaluation, are based upon our historical results for production history, oil and natural gas prices, lifting and development costs, ownership interests and other required data. Our Reservoir Engineering Department, comprised of qualified petroleum engineers and technical support staff, works with our operating, accounting, land and marketing departments in order to accumulate the information required for the reserves estimation process. Our Vice President of Reservoir Engineering is the primary person in charge of overseeing our reserve estimates and our Reservoir Engineering Department. He has a BS Degree and a Masters Degree in Petroleum Engineering, is a Registered Professional Engineer and has over thirty-five years of experience in various technical roles within the oil and gas industry. During the reserves estimation process our petroleum engineers work with Lee Keeling to ensure that all data we provide is properly reflected in the final reserves estimates and they consult with Lee Keeling throughout the reserves estimation process on technical questions regarding the reserve estimates. We also regularly communicate with Lee Keeling throughout the year about our operations and the potential impact of operational changes and events on our reserve estimates.

We did not provide estimates of total proved oil and natural gas reserves during the years ended December 31, 2010, 2011 or 2012 to any federal authority or agency, other than the SEC.

 

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Drilling Activity Summary

During the three-year period ended December 31, 2012, we drilled development and exploratory wells as set forth in the table below:

 

     2010      2011      2012  
     Gross        Net        Gross        Net        Gross        Net    

Development:

                 

Oil

                     17         16.2         78         51.0   

Gas

     65         41.1         61         26.6         7         3.2   

Dry

                                               
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     65         41.1         78         42.8         85         54.2   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Exploratory:

                 

Oil

     3         3.0         3         3.0                   

Gas

     10         5.2         6         1.9                   

Dry

                                               
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     13         8.2         9         4.9                   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

         78         49.3             87         47.7         85         54.2   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

In 2013 to the date of this report, we have drilled ten wells (7.2 net to us) and we have eight wells (5.0 net to us) that are in the process of being drilled.

Producing Well Summary

The following table sets forth the gross and net producing oil and natural gas wells in which we owned an interest at December 31, 2012:

 

     Oil      Natural Gas  
     Gross      Net      Gross      Net  

Arkansas

                     15         8.0   

Kansas

                     9         5.0   

Kentucky

                     86         76.1   

Louisiana

     17         5.4         450         251.6   

New Mexico

     1                 92         14.1   

Oklahoma

     10         1.2         127         17.9   

Texas

     141         96.1         669         437.2   

Wyoming

                     26         1.9   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

         169         102.7         1,474         811.8   
  

 

 

    

 

 

    

 

 

    

 

 

 

We operate 962 of the 1,643 producing wells presented in the above table. As of December 31, 2012, we owned interests in 14 wells containing multiple completions, which means that a well is producing from more than one completed zone. Wells with more than one completion are reflected as one well in the table above.

 

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Acreage

The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2012, all of which is onshore in the continental United States. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.

 

     Developed      Undeveloped  
     Gross      Net      Gross      Net  

Arkansas

     1,280         684                   

Kansas

     6,400         4,064                   

Kentucky

     7,206         5,773                   

Louisiana

     95,516         60,597         24,576         18,910   

New Mexico

     10,240         1,896                   

Oklahoma

     38,080         5,707                   

Texas

     123,553         74,361         96,090         60,968   

Wyoming

     13,440         927                   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     295,715         154,009         120,666           79,878   
  

 

 

    

 

 

    

 

 

    

 

 

 

Our undeveloped acreage expires as follows:

 

Expires in 2013

     29

Expires in 2014

     38

Expires in 2015

     10

Thereafter

     23
  

 

 

 
     100
  

 

 

 

Title to our oil and natural gas properties is subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the oil and gas industry, liens incident to operating agreements and for current taxes not yet due and other minor encumbrances. All of our oil and natural gas properties are pledged as collateral under our bank credit facility. As is customary in the oil and gas industry, we are generally able to retain our ownership interest in undeveloped acreage by production of existing wells, by drilling activity which establishes commercial reserves sufficient to maintain the lease, by payment of delay rentals or by the exercise of contractual extension rights. The Company anticipates retaining ownership of a substantial amount of the acreage with primary terms expiring in 2013 through drilling activity or by extending the leases.

Markets and Customers

The market for oil and natural gas produced by us depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Our oil production is currently sold under short-term contracts with a duration of six months or less. The contracts require the purchasers to purchase the amount of oil production that is available at prices

 

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tied to the spot oil markets. Our natural gas production is primarily sold under contracts with various terms and priced on first of the month index prices or on daily spot market prices. Approximately 89% of our 2012 natural gas sales were priced utilizing first of the month index prices and approximately 11% were priced utilizing daily spot prices. BP Energy Company and its subsidiaries and Shell Oil Company and its subsidiaries accounted for 42% and 27%, respectively, of our total 2012 sales. The loss of either of these customers would not have a material adverse effect on us as there is an available market for our crude oil and natural gas production from other purchasers.

We have entered into longer term marketing arrangements to ensure that we have adequate transportation to get our natural gas production in North Louisiana to the markets. As an alternative to constructing our own gathering and treating facilities, we have entered into a variety of gathering and treating agreements with midstream companies to transport our natural gas to the long-haul natural gas pipelines. We have entered into certain agreements with a major natural gas marketing company to provide us with firm transportation for 80,000 MMBtus per day for our North Louisiana natural gas production on the long-haul pipelines. These agreements expire from 2013 to 2019. To the extent we are not able to deliver the contracted natural gas volumes, we may be responsible for the transportation costs. Our production available to deliver under these agreements in North Louisiana is expected to exceed the firm transportation arrangements we have in place. In addition, the marketing company managing the firm transportation is required to use reasonable efforts to supplement our deliveries should we have a shortfall during the term of the agreements.

Competition

The oil and gas industry is highly competitive. Competitors include major oil companies, other independent energy companies and individual producers and operators, many of which have financial resources, personnel and facilities substantially greater than we do. We face intense competition for the acquisition of oil and natural gas properties and leases for oil and gas exploration.

Regulation

General. Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulation, as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members. The Federal Energy Regulatory Commission, or “FERC,” regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938, or “NGA,” and the Natural Gas Policy Act of 1978, or “NGPA.” In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting all “first sales” of natural gas, effective January 1, 1993, subject to the terms of any private contracts that may be in effect. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, in the future Congress could reenact price controls or enact other legislation with detrimental impact on many aspects of our business. Under the provisions of the Energy Policy Act of 2005 (the “2005 Act”), the NGA has been amended to prohibit any form of market manipulation with the purchase or sale of natural gas, and the FERC has issued new regulations that are intended to increase natural gas pricing transparency. The 2005 Act has also significantly increased the penalties for violations of the NGA. The FERC has issued Order No. 704 et al. which requires a market participant to make an annual filing if it has sales or purchases equal to or greater than 2.2 million MMBtu in the reporting year to facilitate price transparency.

 

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Regulation and transportation of natural gas.    Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. The FERC requires interstate pipelines to provide open-access transportation on a not unduly discriminatory basis for similarly situated shippers. The FERC frequently reviews and modifies its regulations regarding the transportation of natural gas, with the stated goal of fostering competition within the natural gas industry.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The Texas Railroad Commission has been changing its regulations governing transportation and gathering services provided by intrastate pipelines and gatherers. While the changes by these state regulators affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC or state regulators will take on these matters; however, we do not believe that we will be affected differently in any material respect than other natural gas producers with which we compete by any action taken.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach pursued by the FERC, Congress and state regulatory authorities will continue.

Federal leases.    Some of our operations are located on federal oil and natural gas leases that are administered by the Bureau of Land Management (“BLM”) of the United States Department of the Interior. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed Department of Interior and BLM regulations and orders that are subject to interpretation and change. These leases are also subject to certain regulations and orders promulgated by the Department of Interior’s Bureau of Ocean Energy Management, Regulation & Enforcement (“BOEMRE”), through its Minerals Revenue Management Program, which is responsible for the management of revenues from both onshore and offshore leases.

Oil and natural gas liquids transportation rates.    Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. The price received from the sale of these products may be affected by the cost of transporting the products to market.

The FERC’s regulation of pipelines that transport crude oil, condensate and natural gas liquids under the Interstate Commerce Act is generally more light-handed than the FERC’s regulation of natural gas pipelines under the NGA. FERC-regulated pipelines that transport crude oil, condensate and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates are permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates governed by the Interstate Commerce Act that allowed for an increase or decrease in the transportation rates. The FERC’s regulations include a methodology for such pipelines to change their rates through the use of an index system that establishes ceiling levels for such rates. The mandatory five year review in 2005 revised the methodology for this index to be based on Producer Price Index for Finished Goods (PPI-FG) plus 1.3 percent for the period July 1, 2006 through June 30, 2012. The mandatory five year review in 2012 revised the methodology for this index to be based on PPI-FG plus

 

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2.65 percent for the period July 1, 2012 through June 30, 2016. The regulations provide that each year the Commission will publish the oil pipeline index after the PPI-FG becomes available.

With respect to intrastate crude oil, condensate and natural gas liquids pipelines subject to the jurisdiction of state agencies, such state regulation is generally less rigorous than the regulation of interstate pipelines. State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests. Complaints or protests have been infrequent and are usually resolved informally.

We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate or natural gas liquids pipelines will affect us in a way that materially differs from the way it affects other crude oil, condensate and natural gas liquids producers or marketers.

Environmental regulations.    We are subject to stringent federal, state and local laws. These laws, among other things, govern the issuance of permits to conduct exploration, drilling and production operations, the amounts and types of materials that may be released into the environment, the discharge and disposition of waste materials, the remediation of contaminated sites and the reclamation and abandonment of wells, sites and facilities. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup cost without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability. These costs are considered a normal, recurring cost of our on-going operations. Our domestic competitors are generally subject to the same laws and regulations.

We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements or new regulatory schemes such as carbon “cap and trade” programs could have a material adverse effect upon our capital expenditures, earnings or competitive position, including the suspension or cessation of operations in affected areas. As such, there can be no assurance that material cost and liabilities will not be incurred in the future.

The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA,” imposes liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies. In addition, companies that incur liability frequently also confront third party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site.

 

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The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, or “RCRA,” regulates the generation, transportation, storage, treatment and disposal of hazardous wastes and can require cleanup of hazardous waste disposal sites. RCRA currently excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas from regulation as “hazardous waste.” Disposal of such non-hazardous oil and natural gas exploration, development and production wastes usually are regulated by state law. Other wastes handled at exploration and production sites or used in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time, legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from RCRA’s definition of “hazardous wastes,” thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. If such legislation were enacted, it could have a significant impact on our operating costs, as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.

Our operations are also subject to the Clean Air Act, or “CAA,” and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. On April 17, 2012, the U. S. Environmental Protection Agency or “EPA” promulgated new emission standards for the oil and gas industry. These rules require a nearly 95 percent reduction in volatile organic compounds (“VOCs”) emitted from hydraulically fractured gas wells by January 1, 2015. This significant reduction in emissions is to be accomplished primarily through the use of “green completions” (i.e., capturing natural gas that currently escapes to the air). These rules also have notification and reporting requirements. Storage tanks emitting certain levels of VOCs may also require a 95% reduction of VOC emissions by October 1, 2015. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

The Federal Water Pollution Control Act of 1972, as amended, or the “Clean Water Act,” imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters, unless otherwise authorized. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the cost of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

The Federal Safe Drinking Water Act of 1974, as amended, requires EPA to develop minimum federal requirements for Underground Injection Control (“UIC”) programs and other safeguards to protect public health by preventing injection wells from contaminating underground sources of drinking water. The UIC program does not regulate wells that are solely used for production. However, EPA has authority to regulate hydraulic fracturing when diesel fuels are used in fluids or propping agents. In 2012,

 

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EPA issued draft guidance on when UIC permitting requirements apply to fracking fluids containing diesel. We are not able to predict at this time the effect on our operations should EPA require UIC permits be obtained prior to utilizing diesel as a fracking agent. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

Federal regulators require certain owners or operators of facilities that store or otherwise handle oil to prepare and implement spill prevention, control, countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (“OPA”) contains numerous requirements relating to the prevention and response to oil spills in the waters of the United States. The OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages relating to a spill. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities.

Executive Order 13158, issued on May 26, 2000, directs federal agencies to safeguard existing Marine Protected Areas, or “MPAs,” in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate levels of protection for the marine environment. This order has the potential to adversely affect our operations by restricting areas in which we may carry out future exploration and development projects and/or causing us to incur increased operating expenses.

Certain flora and fauna that have officially been classified as “threatened” or “endangered” are protected by the Endangered Species Act. This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area. If endangered species are located in an area we wish to develop, the work could be prohibited or delayed and/or expensive mitigation might be required.

Other statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the Oil Pollution Act, the Emergency Planning and Community Right to Know Act, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands and other protected areas and impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities. In addition, laws such as the National Environmental Policy Act and the Coastal Zone Management Act may make the process of obtaining certain permits more difficult or time consuming, resulting in increased costs and potential delays that could affect the viability or profitability of certain activities.

Certain statutes such as the Emergency Planning and Community Right to Know Act require the reporting of hazardous chemicals manufactured, processed, or otherwise used, which may lead to heightened scrutiny of the company’s operations by regulatory agencies or the public. In 2012, the EPA adopted a new reporting requirement, the Petroleum and Natural Gas Systems Greenhouse Gas Reporting Rule (40 C.F.R. Part 98, Subpart W), which requires certain onshore petroleum and natural gas facilities to begin collecting data on their emissions of greenhouse gases (“GHGs”) in January 2012, with the first annual reports of those emissions due on September 28, 2012. GHGs include gases such as methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning natural gas. Different GHGs have different global warming potentials with CO2 having the lowest global warming potential, so

 

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emissions of GHGs are typically expressed in terms of CO2 equivalents, or CO2e. The rule applies to facilities that emit 25,000 metric tons of CO2e or more per year, and requires onshore petroleum and natural gas operators to group all equipment under common ownership or control within a single hydrocarbon basin together when determining if the threshold is met. We have determined that these new reporting requirements apply to us and we believe we have met all of the EPA required reporting deadlines and strive to ensure accurate and consistent emissions data reporting. Other EPA actions with respect to the reduction of greenhouse gases (such as EPA’s Greenhouse Gas Endangerment Finding, EPA’s Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule) and various state actions have or could impose mandatory reductions in greenhouse gas emissions. We are unable to predict at this time how much the cost of compliance with any legislation or regulation of greenhouse gas emissions will be in future periods.

Such changes in environmental laws and regulations which result in more stringent and costly reporting, or waste handling, storage, transportation, disposal or cleanup activities, could materially affect companies operating in the energy industry. Adoption of new regulations further regulating emissions from oil and gas production could adversely affect our business, financial position, results of operations and prospects, as could the adoption of new laws or regulations which levy taxes or other costs on greenhouse gas emissions from other industries, which could result in changes to the consumption and demand for natural gas. We may also be assessed administrative, civil and/or criminal penalties if we fail to comply with any such new laws and regulations applicable to oil and natural gas production.

We maintain insurance against “sudden and accidental” occurrences, which may cover some, but not all, of the risks described above. Most significantly, the insurance we maintain will not cover the risks described above which occur over a sustained period of time. Further, there can be no assurance that such insurance will continue to be available to cover all such cost or that such insurance will be available at a cost that would justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and results of operations.

Regulation of oil and natural gas exploration and production.    Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits and drilling bonds for the drilling of wells, regulating the location of wells, the method of drilling and casing wells and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing, plugging and abandonment of such wells. Some state statutes limit the rate at which oil and natural gas can be produced from our properties.

State regulation.    Most states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rate of production may be regulated and the maximum daily production allowable from both oil and gas wells may be established on a market demand or conservation basis or both.

Office and Operations Facilities

Our executive offices are located at 5300 Town and Country Blvd., Suite 500 in Frisco, Texas 75034 and our telephone number is (972) 668-8800. We lease office space in Frisco, Texas covering 66,382 square feet at a monthly rate of $118,934. This lease expires on December 31, 2021. We also own production offices and pipe yard facilities near Marshall, Midland, Pecos and Zapata, Texas; Logansport, Louisiana and Guston, Kentucky.

 

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Employees

As of December 31, 2012, we had 116 employees and utilized contract employees for certain of our field operations. We consider our employee relations to be satisfactory.

Directors and Executive Officers

The following table sets forth certain information concerning our executive officers and directors.

 

Name

  

Position with Company

   Age  

M. Jay Allison

   President, Chief Executive Officer and Chairman of the Board of Directors      57   

Roland O. Burns

   Senior Vice President, Chief Financial Officer, Secretary, Treasurer and Director      52   

Mark A. Williams

   Chief Operating Officer and Vice President of Operations      51   

Gerry L. Blackshear

   Vice President of Exploration      54   

D. Dale Gillette

   Vice President of Land and General Counsel      67   

Stephen E. Neukom

   Vice President of Marketing      63   

Daniel K. Presley

   Vice President of Accounting and Controller      52   

Russell W. Romoser

   Vice President of Reservoir Engineering      61   

Richard D. Singer

   Vice President of Financial Reporting      58   

Blaine M. Stribling

   Vice President of Corporate Development      42   

David K. Lockett

   Director      58   

Cecil E. Martin

   Director      71   

Frederic D. Sewell

   Director      78   

David W. Sledge

   Director      56   

Nancy E. Underwood

   Director      61   

Executive Officers

A brief biography of each person who serves as a director or executive officer follows below.

M. Jay Allison has been a director since 1987, and our President and Chief Executive Officer since 1988. Mr. Allison was elected Chairman of the board of directors in 1997. From 1987 to 1988, Mr. Allison served as our Vice President and Secretary. From 1981 to 1987, he was a practicing oil and gas attorney with the firm of Lynch, Chappell & Alsup in Midland, Texas. Mr. Allison was Chairman of the Board of Directors of Bois d’Arc Energy, Inc. from the time of its formation in 2004 until its merger with Stone Energy Corporation in 2008. He received B.B.A., M.S. and J.D. degrees from Baylor University in 1978, 1980 and 1981, respectively. Mr. Allison also currently serves as a Director of Tidewater, Inc. and is on the Board of Regents for Baylor University.

Roland O. Burns has been our Senior Vice President since 1994, Chief Financial Officer and Treasurer since 1990, our Secretary since 1991 and a director since 1999. From 1982 to 1990, Mr. Burns was employed by the public accounting firm, Arthur Andersen. During his tenure with Arthur Andersen,

 

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Mr. Burns worked primarily in the firm’s oil and gas audit practice. Mr. Burns was a director, Senior Vice President and the Chief Financial Officer of Bois d’Arc Energy, Inc. from the time of its formation in 2004 until its merger with Stone Energy Corporation in 2008. Mr. Burns received B.A. and M.A. degrees from the University of Mississippi in 1982 and is a Certified Public Accountant. Mr. Burns also serves on the Board of Directors of the University of Mississippi Foundation.

Mark A. Williams was appointed our Chief Operating Officer in May 2012. From 2011 to 2012, he served as Vice President of Operations. From 2007 to 2011, he served as our Engineering and Operations Manager. From 1996 until 2007, Mr. Williams served as our Drilling Manager and as our South Texas District Engineer. Prior to joining Comstock Mr. Williams was a production engineer at Mitchell Energy Corporation and Citation Oil & Gas. Mr. Williams received a B.S. degree in Petroleum Engineering from Texas A&M University in 1984.

Gerry L. Blackshear was named our Vice President of Exploration in May 2012. From 2007 to 2011 Mr. Blackshear served as our Geoscience Manager. Prior to joining us, Mr. Blackshear was a lead geologist at Encana Oil & Gas from 2004 to 2007. Prior to 2004 he worked as a senior geologist for several large independent oil and gas exploration and development companies. Mr. Blackshear received a B.S. degree in Geology from East Texas State University in 1981 and is a Certified Petroleum Geologist.

D. Dale Gillette has been our Vice President of Land and General Counsel since 2006. Prior to joining us, Mr. Gillette practiced law extensively in the energy sector for 33 years, most recently as a partner with Gardere Wynne Sewell LLP, and before that with Locke Liddell & Sapp LLP. During that time he represented independent exploration and production companies and large financial institutions in numerous oil and gas transactions. Mr. Gillette has also served as corporate counsel in the legal department of Mesa Petroleum Co. and in the legal department of Enserch Corp. Mr. Gillette holds B.A. and J.D. degrees from the University of Texas and is a member of the State Bar of Texas.

Stephen E. Neukom has been our Vice President of Marketing since 1997 and has served as our manager of oil and natural gas marketing since 1996. From 1994 to 1996, Mr. Neukom served as vice president of Comstock Natural Gas, Inc., our former wholly owned gas marketing subsidiary. Prior to joining us, Mr. Neukom was senior vice president of Victoria Gas Corporation from 1987 to 1994. Mr. Neukom received a B.B.A. degree from the University of Texas in 1972.

Daniel K. Presley has been our Vice President of Accounting since 1997 and has been with us since 1989, serving as controller since 1991. Prior to joining us, Mr. Presley had six years of experience with several independent oil and gas companies including AmBrit Energy, Inc. Prior thereto, Mr. Presley spent two and one-half years with B.D.O. Seidman, a public accounting firm. Mr. Presley received a B.B.A. degree from Texas A & M University in 1983.

Russell W. Romoser was named our Vice President of Reservoir Engineering in May 2012. Mr. Romoser has over 35 years of experience as a reservoir engineer both with industry and with a petroleum engineering consulting firm. Prior to joining us, Mr. Romoser served eleven years as the Acquisitions Engineering Manager for EXCO Resources, Inc. Mr. Romoser received a B.S. Degree in Petroleum Engineering in 1975 and a Masters Degree in Petroleum Engineering in 1976 from the University of Texas and is a Registered Professional Engineer in Oklahoma and Texas.

Richard D. Singer has been our Vice President of Financial Reporting since 2005. Mr. Singer has over 36 years of experience in financial accounting and reporting. Prior to joining us, Mr. Singer most recently served as an assistant controller for Holly Corporation from 2004 to 2005 and as assistant controller for Santa Fe International Corporation from 1988 to 2002. Mr. Singer received a B.S. degree from the Pennsylvania State University in 1976 and is a Certified Public Accountant.

 

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Blaine M. Stribling was named our Vice President of Corporate Development in May 2012. From 2007 to 2011, Mr. Stribling served as our Asset & Corporate Development Manager. Prior to joining us, Mr. Stribling managed a development project team at Encana Oil & Gas from 2005 to 2007. Prior to 2005 he worked in various petroleum engineering operations management positions of increasing responsibility for several independent oil and gas exploration and development companies. Mr. Stribling received a B.S. Degree in Petroleum Engineering from the Colorado School of Mines.

Outside Directors

David K. Lockett has served as a director since 2001. Mr. Lockett was a Vice President with Dell Inc. and held executive management positions in several divisions within Dell from 1991 until his retirement from Dell in 2012. Mr. Lockett, who has over 35 years of experience in the technology industry, is presently considering opportunities to provide consulting services for small and mid-size companies. Mr. Lockett was a director of Bois d’Arc Energy, Inc. from May 2005 until its merger with Stone Energy Corporation in August 2008. Mr. Lockett received a B.B.A. degree from Texas A&M University in 1976.

Cecil E. Martin has served as a director since 1989 and is currently the chairman of our audit committee and our Lead Director. Mr. Martin is an independent commercial real estate investor who has primarily been managing his personal real estate investments since 1991. From 1973 to 1991, he also served as chairman of a public accounting firm in Richmond, Virginia. Mr. Martin was a director and chairman of the Audit Committee of Bois d’Arc Energy, Inc. from May 2005 until its merger with Stone Energy Corporation in August 2008. Mr. Martin also serves on the board of directors of Crosstex Energy, Inc. and Crosstex Energy, L.P. and on the Board of Directors and Audit Committee of Garrison Capital, a privately held business development company. Mr. Martin holds a B.B.A. degree from Old Dominion University and is a Certified Public Accountant.

Frederic D. Sewell was first elected as a director in May 2012. Mr. Sewell has extensive experience in the oil and gas industry, where he has had a distinguished career as an executive leader and a petroleum engineer. Mr. Sewell was the co-founder of Netherland, Sewell and Associates, Inc., a worldwide oil and gas consulting firm, where he served as the chairman and chief executive officer until his retirement in 2008. Mr. Sewell is presently the President and Chief Executive Officer of Sovereign Resources, LLC, an exploration and production company that he founded. Mr. Sewell holds a B.S. Degree in Petroleum Engineering from the University of Texas.

David W. Sledge has served as a director since 1996. Mr. Sledge is the Chief Operating Officer of ProPetro Services, Inc. Mr. Sledge was President and Chief Operating Officer of Sledge Drilling Company until it was acquired by Basic Energy Services, Inc. in April 2007 and served as a Vice President of Basic Energy Services, Inc. from April 2007 to February 2009. He served as an area operations manager for Patterson-UTI Energy, Inc. from May 2004 until January 2006. From March 2009 through October 2011, and from October 1996 until May 2004, Mr. Sledge managed his personal investments in oil and gas exploration activities. Mr. Sledge was a director of Bois d’Arc Energy, Inc. from May 2005 until its merger with Stone Energy Corporation in August 2008. Mr. Sledge is a past director of the International Association of Drilling Contractors and is a past chairman of the Permian Basin chapter of this association. He received a B.B.A. degree from Baylor University in 1979.

Nancy E. Underwood has served as a director since 2004. Ms. Underwood is owner and President of Underwood Financial Ltd., a position she has held since 1986. Ms. Underwood holds B.S. and J.D. degrees from Emory University and practiced law at an Atlanta, Georgia based law firm before joining River Hill Development Corporation in 1981. Ms. Underwood currently serves on the Executive Board and Campaign Steering Committee of the Southern Methodist University Dedman School of Law and on the Board of Directors of Texas Health Presbyterian Foundation.

 

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Available Information

Our executive offices are located at 5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034. Our telephone number is (972) 668-8800. We file annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a website that contains reports, proxy and information statements, and other information that is electronically filed with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov. We also make available free of charge on our website (www.comstockresources.com) our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we file such material with, or furnish it to, the SEC.

 

ITEM 1A.     RISK FACTORS

You should carefully consider the following risk factors as well as the other information contained or incorporated by reference in this report, as these important factors, among others, could cause our actual results to differ from our expected or historical results. It is not possible to predict or identify all such factors. Consequently, you should not consider any such list to be a complete statement of all of our potential risks or uncertainties.

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition, cash flow, liquidity or results of operations and our ability to meet our capital expenditure obligations and financial commitments and to implement our business strategy.

Our business is heavily dependent upon the prices of, and demand for, oil and natural gas. Historically, the prices for oil and natural gas have been volatile and are likely to remain volatile in the future. Prices for oil remained relatively strong in 2012, but our realized natural gas prices continued to decline in 2012, reaching a thirteen year low of $2.03 per Mcf in the second quarter of 2012. The continued growth in production of natural gas in the United States has increased supply and resulted in high natural gas storage inventories. As a result, natural gas prices continue to face downward pressures.

The prices we receive for our oil and natural gas production and the level of such production will be subject to wide fluctuations and depend on numerous factors beyond our control, including the following:

 

   

the domestic and foreign supply of oil and natural gas;

   

weather conditions;

   

the price and quantity of imports of oil and natural gas;

   

political conditions and events in other oil-producing and natural gas-producing countries, including embargoes, hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;

   

the actions of the Organization of Petroleum Exporting Countries, or OPEC;

   

domestic government regulation, legislation and policies;

   

the level of global oil and natural gas inventories;

   

technological advances affecting energy consumption;

   

the price and availability of alternative fuels; and

   

overall economic conditions.

 

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If the decline in the price of natural gas that first started in 2008 continues through 2013, the lower prices will adversely affect:

 

   

our revenues, profitability and cash flow from operations;

   

the value of our proved oil and natural gas reserves;

   

the economic viability of certain of our drilling prospects;

   

our borrowing capacity; and

   

our ability to obtain additional capital.

We have entered into certain oil price hedging arrangements on certain of our anticipated sales in 2013. In the future we may enter into additional hedging arrangements in order to reduce our exposure to price risks. Such arrangements would limit our ability to benefit from increases in oil and natural gas prices.

The recent recession could have a material adverse impact on our financial position, results of operations and cash flows.

The oil and gas industry is cyclical and tends to reflect general economic conditions. The United States and other countries have been in a recession which could continue through 2013 and beyond, and the capital markets have experienced significant volatility. The recession has had an adverse impact on demand and pricing for oil and natural gas. A continuation of the recession could have a further negative impact on oil and natural gas prices. Our operating cash flows and profitability will be significantly affected by declining oil and natural gas prices. Further declines in oil and natural gas prices may also impact the value of our oil and gas reserves, which could result in future impairment charges to reduce the carrying value of our oil and gas properties and our marketable securities. Our future access to capital could be limited due to tightening credit markets and volatile capital markets. If our access to capital is limited, development of our assets may be delayed or limited, and we may not be able to execute our growth strategy.

Our future production and revenues depend on our ability to replace our reserves.

Our future production and revenues depend upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we must continue our acquisition and drilling activities. We cannot assure you, however, that our acquisition and drilling activities will result in significant additional reserves or that we will have continuing success drilling productive wells at low finding and development costs. Furthermore, while our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return.

A prospect is a property in which we own an interest or have operating rights and that has what our geoscientists believe, based on available seismic and geological information, to be an indication of potential oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional evaluation and interpretation. There is no way

 

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to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. The analysis that we perform using data from other wells, more fully explored prospects and/or producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling prospects. If we drill additional unsuccessful wells, our drilling success rate may decline and we may not achieve our targeted rate of return.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as restrict our access to our oil and gas reserves.

Hydraulic fracturing is an essential and common practice that is used to stimulate production of oil and natural gas from dense subsurface rock formations such as shale and tight sands. We routinely apply hydraulic fracturing techniques in completing our wells. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the oil or natural gas to flow to the wellbore. The use of hydraulic fracturing is necessary to produce commercial quantities of oil and natural gas from many reservoirs including the Haynesville shale, Bossier shale, Eagle Ford shale, Wolfcamp shale, Bone Spring, Cotton Valley and other tight natural gas and oil reservoirs. Substantially all of our proved oil and gas reserves that are currently not producing and our undeveloped acreage require hydraulic fracturing to be productive. All of the wells being drilled by us in 2013 utilize hydraulic fracturing in their completion. We estimate we will incur approximately $178.0 million for hydraulic fracturing services in connection with our 2013 drilling and completion program.

The use of hydraulic fracturing in our well completion activities could expose us to liability for negative environmental effects that might occur. Although we have not had any incidents related to hydraulic fracturing operations that we believe have caused any negative environmental effects, we have established operating procedures to respond and report any unexpected fluid discharge which might occur during our operations, including plans to remediate any spills that might occur. In the event that we were to suffer a loss related to hydraulic fracturing operations, our insurance will be net of a $25,000 deductible and our ability to recover costs will be limited to a total aggregate policy limit of $26.0 million, which may or may not be sufficient to pay the full amount of our losses incurred.

Drilling and completion activities are typically regulated by state oil and natural gas commissions. Our drilling and completion activities are conducted primarily in Louisiana and Texas. Texas adopted a law in June 2012 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic-fracturing process. Several proposals are before the United States Congress that, if implemented, would subject the process of hydraulic fracturing to regulation under the Safe Drinking Water Act. At the direction of Congress, the EPA is currently conducting an extensive, multi-year study into the potential effects of hydraulic fracturing on underground sources of drinking water, and the results of that study have the potential to impact the likelihood or scope of future legislation or regulation.

Potential changes to US federal tax regulations, if passed, could have an adverse effect on us.

The United States Congress continues to consider imposing new taxes and repeal of many tax incentives and deductions that are currently used by independent oil and gas producers. Examples of changes being considered that would impact us are: elimination of the ability to fully deduct intangible

 

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drilling costs in the year incurred, repeal of the manufacturing tax deduction for oil and gas companies, increasing the geological and geophysical cost amortization period, and implementation of a fee on non-producing leases located on federal lands. If these proposals are enacted, our current income tax liability will increase, potentially significantly, which would have a negative impact on our cash flow from operating activities. A reduction in operating cash flow could require us to reduce our drilling activities. Since none of these proposals have yet to be included in new legislation, we do not know the ultimate impact they may have on our business.

Our debt service requirements could adversely affect our operations and limit our growth.

We had $1.3 billion in debt as of December 31, 2012, and our ratio of total debt to total capitalization was approximately 59%.

Our outstanding debt will have important consequences, including, without limitation:

 

   

a portion of our cash flow from operations will be required to make debt service payments;

   

our ability to borrow additional amounts for working capital, capital expenditures (including acquisitions) or other purposes will be limited; and

   

our debt could limit our ability to capitalize on significant business opportunities, our flexibility in planning for or reacting to changes in market conditions and our ability to withstand competitive pressures and economic downturns.

In addition, future acquisition or development activities may require us to alter our capitalization significantly. These changes in capitalization may significantly increase our debt. Moreover, our ability to meet our debt service obligations and to reduce our total debt will be dependent upon our future performance, which will be subject to general economic conditions and financial, business and other factors affecting our operations, many of which are beyond our control. If we are unable to generate sufficient cash flow from operations in the future to service our indebtedness and to meet other commitments, we will be required to adopt one or more alternatives, such as refinancing or restructuring our indebtedness, selling material assets or seeking to raise additional debt or equity capital. We cannot assure you that any of these actions could be effected on a timely basis or on satisfactory terms or that these actions would enable us to continue to satisfy our capital requirements.

Our bank credit facility contains a number of significant covenants. These covenants will limit our ability to, among other things:

 

   

borrow additional money;

   

merge, consolidate or dispose of assets;

   

make certain types of investments;

   

enter into transactions with our affiliates; and

   

pay dividends.

Our failure to comply with any of these covenants could cause a default under our bank credit facility and the respective indentures governing our senior notes. A default, if not waived, could result in acceleration of our indebtedness, in which case the debt would become immediately due and payable. If this occurs, we may not be able to repay our debt or borrow sufficient funds to refinance it given the current status of the credit markets. Even if new financing is available, it may not be on terms that are acceptable to us. Complying with these covenants may cause us to take actions that we otherwise would not take or not take actions that we otherwise would take.

 

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The unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel and oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry has experienced a shortage of drilling rigs, equipment, supplies and qualified personnel in recent years as the result of higher demand for these services. Costs and delivery times of rigs, equipment and supplies have been substantially greater than they were several years ago. In addition, demand for, and wage rates of, qualified drilling rig crews have escalated due to the higher activity levels. Shortages of drilling rigs, equipment or supplies or qualified personnel in the areas in which we operate could delay or restrict our exploration and development operations, which in turn could adversely affect our financial condition and results of operations because of our concentration in those areas.

Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our future success will depend on the success of our exploration and development activities. Exploration activities involve numerous risks, including the risk that no commercially productive natural gas or oil reserves will be discovered. In addition, these activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their costs, unsuccessful wells can hurt our efforts to replace production and reserves.

Our business involves a variety of operating risks, including:

 

   

unusual or unexpected geological formations;

   

fires;

   

explosions;

   

blow-outs and surface cratering;

   

uncontrollable flows of natural gas, oil and formation water;

   

natural disasters, such as hurricanes, tropical storms and other adverse weather conditions;

   

pipe, cement, or pipeline failures;

   

casing collapses;

   

mechanical difficulties, such as lost or stuck oil field drilling and service tools;

   

abnormally pressured formations; and

   

environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

If we experience any of these problems, well bores, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations.

We could also incur substantial losses as a result of:

 

   

injury or loss of life;

   

severe damage to and destruction of property, natural resources and equipment;

   

pollution and other environmental damage;

   

clean-up responsibilities;

   

regulatory investigation and penalties;

   

suspension of our operations; and

   

repairs to resume operations.

 

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We pursue acquisitions as part of our growth strategy and there are risks in connection with acquisitions.

Our growth has been attributable in part to acquisitions of producing properties and companies. We expect to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. However, we cannot assure you that suitable acquisition candidates will be identified in the future, or that we will be able to finance such acquisitions on favorable terms. In addition, we compete against other companies for acquisitions, and we cannot assure you that we will successfully acquire any material property interests. Further, we cannot assure you that future acquisitions by us will be integrated successfully into our operations or will increase our profits.

The successful acquisition of producing properties requires an assessment of numerous factors beyond our control, including, without limitation:

 

   

recoverable reserves;

   

exploration potential;

   

future oil and natural gas prices;

   

operating costs; and

   

potential environmental and other liabilities.

In connection with such an assessment, we perform a review of the subject properties that we believe to be generally consistent with industry practices. The resulting assessments are inexact and their accuracy uncertain, and such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is made.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics or geographic location than our existing properties. While our current operations are focused in the East Texas/North Louisiana, South Texas and West Texas regions, we may pursue acquisitions or properties located in other geographic areas.

We operate in a highly competitive industry, and our failure to remain competitive with our competitors, many of which have greater resources than we do, could adversely affect our results of operations.

The oil and natural gas industry is highly competitive in the search for and development and acquisition of reserves. Our competitors often include companies that have greater financial and personnel resources than we do. These resources could allow those competitors to price their products and services more aggressively than we can, which could hurt our profitability. Moreover, our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to close transactions in a highly competitive environment.

Our competitors may use superior technology that we may be unable to afford or which would require costly investment by us in order to compete.

If our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow

 

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them to enjoy technological advances and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. All of these factors may inhibit our ability to acquire additional prospects and compete successfully in the future.

Substantial exploration and development activities could require significant outside capital, which could dilute the value of our common shares and restrict our activities. Also, we may not be able to obtain needed capital or financing on satisfactory terms, which could lead to a limitation of our future business opportunities and a decline in our oil and natural gas reserves.

We expect to expend substantial capital in the acquisition of, exploration for and development of oil and natural gas reserves. In order to finance these activities, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of non-strategic assets or other means. The issuance of additional equity securities could have a dilutive effect on the value of our common shares, and may not be possible on terms acceptable to us given the current volatility in the financial markets. The issuance of additional debt would require that a portion of our cash flow from operations be used for the payment of interest on our debt, thereby reducing our ability to use our cash flow to fund working capital, capital expenditures, acquisitions, dividends and general corporate requirements, which could place us at a competitive disadvantage relative to other competitors. Additionally, if our revenues decrease as a result of lower oil or natural gas prices, operating difficulties or declines in reserves, our ability to obtain the capital necessary to undertake or complete future exploration and development programs and to pursue other opportunities may be limited, which could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could result in a decline in our oil and natural gas reserves.

If oil prices decline and natural gas prices remain low or continue to decline, we may be required to write-down the carrying values and/or the estimates of total reserves of our oil and natural gas properties, which would constitute a non-cash charge to earnings and adversely affect our results of operations.

Accounting rules applicable to us require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur non-cash charges in the future, which could have a material adverse effect on our results of operations in the period taken. We may also reduce our estimates of the reserves that may be economically recovered, which could have the effect of reducing the total value of our reserves. Such a reduction in carrying value could impact our borrowing ability and may result in accelerating the repayment date of any outstanding debt.

Our reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve

 

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estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve estimates are to some degree imprecise, the quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas prices may all differ materially from those assumed in these estimates. The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves is only estimated and should not be construed as the current market value of the oil and natural gas reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Any future downward revisions could adversely affect our financial condition, our borrowing ability, our future prospects and the value of our common stock.

As of December 31, 2012, 38% of our total proved reserves were undeveloped and 8% were developed non-producing. These reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced at the time periods we have planned, at the costs we have budgeted, or at all. As a result, we may not find commercially viable quantities of oil and natural gas, which in turn may result in a material adverse effect on our results of operations.

If we are unsuccessful at marketing our oil and natural gas at commercially acceptable prices, our profitability will decline.

Our ability to market oil and natural gas at commercially acceptable prices depends on, among other factors, the following:

 

   

the availability and capacity of gathering systems and pipelines;

   

federal and state regulation of production and transportation;

   

changes in supply and demand; and

   

general economic conditions.

Our inability to respond appropriately to changes in these factors could negatively affect our profitability.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and processing facilities. Our ability to market our production depends in a substantial part on the availability and capacity of gathering systems, pipelines and processing facilities, in some cases owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for a lack of a market or because of the inadequacy or unavailability of pipelines or gathering system capacity. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market.

 

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We depend on our key personnel and the loss of any of these individuals could have a material adverse effect on our operations.

We believe that the success of our business strategy and our ability to operate profitably depend on the continued employment of M. Jay Allison, our President and Chief Executive Officer, and a limited number of other senior management personnel. Loss of the services of Mr. Allison or any of those other individuals could have a material adverse effect on our operations.

Our insurance coverage may not be sufficient or may not be available to cover some liabilities or losses that we may incur.

If we suffer a significant accident or other loss, our insurance coverage will be net of our deductibles and may not be sufficient to pay the full current market value or current replacement value of our lost investment, which could result in a material adverse impact on our operations and financial condition. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Because third party drilling contractors are used to drill our wells, we may not realize the full benefit of workers’ compensation laws in dealing with their employees. In addition, some risks, including pollution and environmental risks, generally are not fully insurable.

We are subject to extensive governmental laws and regulations that may adversely affect the cost, manner or feasibility of doing business.

Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and natural gas, and operating safety. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with governmental laws and regulations, such as:

 

   

lease permit restrictions;

   

drilling bonds and other financial responsibility requirements, such as plug and abandonment bonds;

   

spacing of wells;

   

unitization and pooling of properties;

   

safety precautions;

   

regulatory requirements; and

   

taxation.

Under these laws and regulations, we could be liable for:

 

   

personal injuries;

   

property and natural resource damages;

   

well reclamation costs; and

   

governmental sanctions, such as fines and penalties.

Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.

 

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Our operations may incur substantial liabilities to comply with environmental laws and regulations.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment and otherwise relating to environmental protection. These laws and regulations:

 

   

require the acquisition of one or more permits before drilling commences;

   

impose limitations on where drilling can occur and/or requires mitigation before authorizing drilling in certain locations;

   

restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;

   

require reporting of significant releases, and annual reporting of the nature and quantity of emissions, discharges and other releases into the environment;

   

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

   

impose substantial liabilities for pollution resulting from our operations.

Failure to comply with these laws and regulations may result in:

 

   

the assessment of administrative, civil and criminal penalties;

   

the incurrence of investigatory or remedial obligations; and

   

the imposition of injunctive relief.

In June 2009 the United States House of Representatives passed the American Clean Energy and Security Act of 2009. A similar bill, the Clean Energy Jobs and American Power Act, introduced in the Senate, did not pass. Both bills contained the basic feature of establishing a “cap and trade” system for restricting greenhouse gas emissions in the United States. Under such a system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary over time to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. It appears that the prospects for a cap and trade system such as that proposed in these bills have dimmed significantly; however, the EPA has moved ahead with its efforts to regulate GHG emissions from certain sources by rule. The EPA issued Subpart W of the Final Mandatory Reporting of Greenhouse Gases Rule, which required petroleum and natural gas systems that emit 25,000 metric tons of CO2e or more per year to begin collecting GHG emissions data under a new reporting system. We believe we have met all of the reporting requirements under these new regulations. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The EPA has adopted regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. Since all of our oil and natural gas production is in the United States, these laws or regulations that have been or may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur substantial increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.

In June 2010 the Bureau of Land Management issued a proposed oil and gas leasing reform. The proposal would require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources on federal lands, increased public engagement in the development of Master Leasing Plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process with greater public involvement in the identification of key environmental resource values before a parcel is leased. New leases would incorporate adaptive management stipulations, requiring lessees to monitor and respond to observed environmental impacts,

 

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possibly through the implementation of expensive new control measures or curtailment of operations, potentially reducing profitability. The proposed policy could have the effect of reducing the amount of new federal lands made available for lease, increasing the competition for and cost of available parcels.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly restrictions on emissions, and/or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed. Future environmental laws and regulations, including proposed legislation regulating climate change, may negatively impact our industry. The costs of compliance with these requirements may have an adverse impact on our financial condition, results of operations and cash flows.

Provisions of our articles of incorporation, bylaws and Nevada law will make it more difficult to effect a change in control of us, which could adversely affect the price of our common stock.

Nevada corporate law and our articles of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us. These provisions include:

 

   

allowing for authorized but unissued shares of common and preferred stock;

   

a classified board of directors;

   

requiring special stockholder meetings to be called only by our chairman of the board, our chief executive officer, a majority of the board or the holders of at least 10% of our outstanding stock entitled to vote at a special meeting;

   

requiring removal of directors by a supermajority stockholder vote;

   

prohibiting cumulative voting in the election of directors; and

   

Nevada control share laws that may limit voting rights in shares representing a controlling interest in us.

These provisions could make an acquisition of us by means of a tender offer or proxy contest or removal of our incumbent directors more difficult. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

None.

ITEM 3.    LEGAL PROCEEDINGS

We are not a party to any legal proceedings which management believes will have a material adverse effect on our consolidated results of operations or financial condition.

ITEM 4.    MINE SAFETY DISCLOSURES

Not applicable.

 

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PART II

 

ITEM 5.    MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed for trading on the New York Stock Exchange under the symbol “CRK.” The following table sets forth, on a per share basis for the periods indicated, the high and low sales prices by calendar quarter for the periods indicated as reported by the New York Stock Exchange.

 

          High      Low  

2011 —

   First Quarter    $ 31.38       $ 23.68   
   Second Quarter    $ 33.00       $ 26.14   
   Third Quarter    $ 33.63       $ 15.40   
   Fourth Quarter    $ 20.21       $ 13.69   

2012 —

   First Quarter    $ 17.79       $ 11.05   
   Second Quarter    $ 18.54       $ 12.56   
   Third Quarter    $ 20.46       $ 14.95   
   Fourth Quarter    $ 21.16       $ 14.40   

As of February 28, 2013, we had 48,303,517 shares of common stock outstanding, which were held by 221 holders of record and approximately 7,900 beneficial owners who maintain their shares in “street name” accounts.

We have never paid cash dividends on our common stock. We presently intend to retain any earnings for the operation and expansion of our business and we do not anticipate paying cash dividends in the foreseeable future. Any future determination as to the payment of dividends will depend upon the results of our operations, capital requirements, our financial condition and such other factors as our board of directors may deem relevant. In addition, we are limited under our bank credit facility and by the terms of the indentures for our senior notes from paying or declaring cash dividends.

During the fourth quarter of 2012, we did not repurchase any of our equity securities.

 

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ITEM 6. SELECTED FINANCIAL DATA

The historical financial data presented in the table below as of and for each of the years in the five-year period ended December 31, 2012 are derived from our consolidated financial statements. The financial results are not necessarily indicative of our future operations or future financial results. The data presented below should be read in conjunction with our consolidated financial statements and the notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” In 2008, we divested our interests in offshore operations which were conducted through our subsidiary Bois d’Arc Energy, Inc. (“Bois d’Arc”). Accordingly, we have adjusted the presentation of selected financial data to reflect the offshore operations on a discontinued basis.

Statement of Operations Data:

 

     Year Ended December 31,  
     2008     2009     2010     2011     2012  
     (In thousands, except per share data)  

Revenues:

          

Oil and gas sales

   $ 563,749      $ 292,583      $ 349,141      $ 434,367      $ 431,923   

Gain on sale of oil and gas properties

     26,560        213                      24,271   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     590,309        292,796        349,141        434,367        456,194   

Operating expenses:

          

Production taxes

     20,648        8,643        9,894        3,670        14,021   

Gathering and transportation

     3,910        8,696        17,256        28,491        27,312   

Lease operating(1)

     62,172        53,560        53,525        46,552        60,620   

Exploration

     5,032        907        2,605        10,148        61,449   

Depreciation, depletion and amortization

     182,179        213,238        213,809        290,776        365,286   

General and administrative, net

     32,266        39,172        37,200        35,172        33,798   

Impairment of oil and gas properties

     922        115        224        60,817        25,368   

Loss on sale of oil and gas properties

                   26,632        57          
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     307,129        324,331        361,145        475,683        587,854   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

     283,180        (31,535     (12,004     (41,316     (131,660

Other income (expenses):

          

Gain on sale of marketable securities

                   16,529        35,118        26,621   

Marketable securities impairment

     (162,672                            

Realized gain from derivatives

                                 9,766   

Unrealized gain from derivatives

                                 11,490   

Interest and other income

     1,656        378        499        790        944   

Interest expense

     (25,336     (16,086     (29,456     (42,688     (64,575
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expenses)

     (186,352     (15,708     (12,428     (6,780     (15,754
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income taxes

     96,828        (47,243     (24,432     (48,096     (147,414

Benefit from (provision for) income taxes

     (38,611     10,772        4,846        14,624        47,354   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations

     58,217        (36,471     (19,586     (33,472     (100,060

Income (loss) from discontinued operations

     193,745 (2)                             
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 251,962      $ (36,471   $ (19,586   $ (33,472   $ (100,060
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Basic net income (loss) per share:

          

Continuing operations

   $ 1.27      $ (0.81   $ (0.43   $ (0.73   $ (2.16

Discontinued operations

     4.23                               
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   $ 5.50      $ (0.81   $ (0.43   $ (0.73   $ (2.16
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Diluted net income (loss) per share:

          

Continuing operations

   $ 1.26      $ (0.81   $ (0.43   $ (0.73   $ (2.16

Discontinued operations

     4.20                               
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   $ 5.46      $ (0.81   $ (0.43   $ (0.73   $ (2.16
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average shares outstanding:

          

Basic

     44,524        45,004        45,561        45,997        46,422   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

     44,813        45,004 (3)      45,561 (3)      45,997 (3)      46,422 (3) 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 

(1) Includes ad valorem taxes.
(2) Includes gain of $158.1 million, net of income taxes of $85.3 million, from the sale of our offshore operations.
(3) Basic and diluted weighted average shares are the same due to the net loss.

 

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Balance Sheet Data:

 

     As of December 31,  
     2008      2009      2010      2011      2012  
     (In thousands)  

Cash and cash equivalents

   $ 6,281       $ 90,472       $ 1,732       $ 8,460       $ 4,471   

Property and equipment, net

     1,444,715         1,576,287         1,816,248         2,509,845         2,470,053   

Total assets

     1,577,890         1,858,961         1,964,214         2,639,884         2,567,143   

Total debt

     210,000         470,836         513,372         1,196,908         1,324,383   

Stockholders’ equity

     1,062,085         1,066,111         1,068,531         1,037,625         933,534   

Cash Flow Data:

 

     Year Ended December 31,  
     2008     2009     2010     2011     2012  
     (In thousands)  

Cash flows provided by operating activities from continuing operations

   $ 450,533      $ 176,257      $ 311,662      $ 284,904      $ 262,229   

Cash flows used for investing activities from continuing operations

     (289,194     (348,777     (440,473     (952,086     (383,720

Cash flows provided by (used for) financing activities from continuing operations

     (452,883     256,711        40,071        673,910        117,502   

Cash flows provided by discontinued operations

     292,260                               

 

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our selected historical consolidated financial data and our accompanying consolidated financial statements and the notes to those financial statements included elsewhere in this report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Overview

We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas in the United States. We own interests in 1,643 producing oil and natural gas wells (914.5 net to us) and we operate 962 of these wells. In managing our business, we are concerned primarily with maximizing return on our stockholders’ equity. To accomplish this goal, we focus on profitably increasing our oil and natural gas reserves and production.

Our future growth will be driven primarily by acquisition, development and exploration activities. In 2012 our growth in production and proved reserves was primarily driven by our successful oil focused drilling activities. Under our current drilling budget, we plan to spend approximately $420.0 million in 2013 for development and exploration activities, which will primarily be focused on oil projects. We plan to drill 85 wells (58.1 net to us) in 2013, of which 75 wells (54.5 net to us) will target oil in our South Texas and West Texas regions and ten will target natural gas in our East Texas / North Louisiana region. However, we could increase or decrease the number of wells that we drill depending on oil and natural gas prices. We do not specifically budget for acquisitions as the timing and size of acquisitions are not predictable.

 

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We use the successful efforts method of accounting, which allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration activities. Accordingly, our exploration costs consist of costs we incur to acquire and reprocess 3-D seismic data, impairments of our unevaluated leasehold where we were not successful in discovering reserves and the costs of unsuccessful exploratory wells that we drill.

We generally sell our oil and natural gas at current market prices at the point our wells connect to third party purchaser pipelines. We have entered into certain transportation and treating agreements with midstream and pipeline companies to transport a substantial portion of our natural gas production in North Louisiana to long-haul gas pipelines. We market our products several different ways depending upon a number of factors, including the availability of purchasers for the product, the availability and cost of pipelines near our wells, market prices, pipeline constraints and operational flexibility. Accordingly, our revenues are heavily dependent upon the prices of, and demand for, oil and natural gas. Oil and natural gas prices have historically been volatile and are likely to remain volatile in the future.

Our operating costs are generally comprised of several components, including costs of field personnel, insurance, repair and maintenance costs, production supplies, fuel used in operations, transportation costs, workover expenses and state production and ad valorem taxes.

Like all oil and natural gas exploration and production companies, we face the constant challenge of replacing our reserves. Although in the past we have offset the effect of declining production rates from existing properties through successful acquisition and drilling efforts, there can be no assurance that we will be able to continue to offset production declines or maintain production at current rates through future acquisitions or drilling activity. Our future growth will depend on our ability to continue to add new reserves in excess of production.

Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and natural gas, and operating safety. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may have an adverse effect on our business, results of operations and financial condition. Applicable environmental regulations require us to remove our equipment after production has ceased, to plug and abandon our wells and to remediate any environmental damage our operations may have caused. The present value of the estimated future costs to plug and abandon our oil and gas wells and to dismantle and remove our production facilities is included in our reserve for future abandonment costs, which was $18.0 million as of December 31, 2012.

 

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Results of Operations

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Our operating data for 2011 and 2012 is summarized below:

 

     Year Ended
December 31,
 
     2011      2012  

Net Production Data:

     

Natural gas (MMcf)

     90,593         82,490   

Oil (MBbls)

     838         2,309   

Natural gas equivalent (MMcfe)

     95,622         96,345   

Average Sales Price:

     

Oil ($/Bbl)

     $95.73         $96.95   

Oil including hedging ($/Bbl)(1)

     $95.73         $101.18   

Natural gas ($/Mcf)

     $3.91         $2.52   

Average equivalent price ($/Mcfe)

     $4.54         $4.48   

Average equivalent price including hedging ($/Mcfe)(1)

     $4.54         $4.58   

Expenses ($ per Mcfe):

     

Production taxes

     $0.04         $0.15   

Gathering and transportation

     $0.30         $0.28   

Lease operating(2)

     $0.48         $0.63   

Depreciation, depletion and amortization(3)

     $3.00         $3.83   

 

 

(1) Includes realized gains from derivatives of $9.8 million in 2012.
(2) Includes ad valorem taxes.
(3) Represents depreciation, depletion and amortization of oil and gas properties only.

Oil and gas sales.    Our oil and gas sales decreased $2.5 million (1%) in 2012 to $431.9 million from sales of $434.4 million in 2011. Our oil production in 2012 increased by 175% while our natural gas production decreased by 9% from our 2011 production levels. On an equivalent unit basis, our production in 2012 increased by 1% over 2011. Our successful drilling program grew our oil production which offset the decline in natural gas production. Prices realized for oil sales increased by 1% in 2012 as compared to 2011 while the average price we realized for natural gas sales decreased by 36% in 2012 as compared to 2011. Our oil hedging program generated $9.8 million in realized gains in 2012. Including the results of our hedging program, our average oil price in 2012 of $101.18 increased 6% above last year’s average price.

Production taxes.    Production taxes increased $10.3 million or 282% to $14.0 million in 2012 from $3.7 million in 2011. The increase in 2012 is due to the significant growth in our oil sales during the year. Much of our natural gas sales in 2011 and 2012 qualify for exemption from state production taxes.

Gathering and transportation.    Gathering and transportation costs in 2012 decreased $1.2 million (4%) to $27.3 million as compared to $28.5 million in 2011 due to the lower natural gas volumes that we produced in North Louisiana in 2012.

Lease operating expenses.    Our lease operating expenses, including ad valorem taxes, of $60.6 million in 2012 were $14.0 million or 30% higher than our operating expenses of $46.6 million in 2011. Our lease operating expense per Mcfe produced increased by 29% to $1.06 per Mcfe in 2012 as compared to $0.82 per Mcfe in 2011. The increase mainly reflects our growing oil production. Our oil wells are typically more costly to operate than our natural gas wells. Oil production comprised 14% of our total production in 2012 as compared to 5% in 2011.

Exploration expense.    We incurred $61.4 million in exploration expense in 2012 as compared to $10.1 million in 2011. Exploration expense in 2012 consisted of $61.3 million of impairments of

 

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unevaluated leasehold costs and $0.1 million for the acquisition of seismic data. Our 2011 exploration cost consisted of $9.8 million of impairments of unevaluated leasehold costs and $0.3 million for the acquisition of seismic data.

Depreciation, depletion and amortization expense (“DD&A”).    DD&A of $365.3 million was an increase of $74.5 million (26%) over DD&A of $290.8 million in 2011. Our DD&A rate per Mcfe produced averaged $3.83 in 2012 as compared to $3.00 for 2011. The increase in DD&A primarily resulted from increased development costs per Mcfe associated with the oil wells drilled in 2012, and the substantial decline in our proved natural gas reserves due to the low natural gas prices in 2012.

Impairment of oil and gas properties.    We recorded impairments to our oil and gas properties of $25.4 million and $60.8 million in 2012 and 2011, respectively. These impairments relate to fields where an impairment was indicated based on estimated future cash flows from the properties.

General and administrative expenses. General and administrative expense of $33.8 million for 2012 was 4% lower than general and administrative expense of $35.2 million for 2011. The decrease primarily reflects lower stock based compensation in 2012. Stock based compensation decreased by $1.3 million to $13.7 million in 2012 as compared to $15.0 million in 2011.

Interest expense.    Interest expense increased $21.9 million (51%) to $64.6 million in 2012 from interest expense of $42.7 million in 2011. The increase was primarily related to the increase in outstanding debt during 2012 including the issuance of $300.0 million in senior notes in June 2012. Average borrowings under our bank credit facility increased to $482.7 million in 2012 as compared to $121.4 million for 2011. The average interest rate on the outstanding borrowings under our credit facility of 3.0% in 2012 was higher than the interest rate of 2.2% in 2011. We capitalized interest of $20.9 million and $13.2 million in 2012 and 2011, respectively, which amounts reduced interest expense.

Income taxes.    The benefit from income taxes increased in 2012 to $47.4 million from $14.6 million in 2011 due to the higher net loss in 2012. Our effective tax rate of 32% in 2012 and 30% in 2011 differed from the federal income tax rate of 35% primarily due to the effect of nondeductible compensation and state income taxes.

Net loss.    We reported a loss of $100.1 million for 2012 as compared to a loss of $33.5 million for 2011. The loss per share for 2012 was $2.16 on weighted average shares outstanding of 46.4 million as compared to a loss per share of $0.73 for 2011 on weighted average shares outstanding of 46.0 million. The loss in 2012 was primarily related to the increase in DD&A expense and impairments of proved and unproved properties of $86.7 million ($56.3 million after income taxes) which were offset in part by gains on sales of properties of $24.3 million ($15.8 million after income taxes) and sales of marketable securities of $26.6 million ($17.3 million after income taxes) and also unrealized gains on our oil derivatives of $11.5 million ($7.5 million after tax). The loss in 2011 was primarily related to the impairments to proved and unproved properties in 2011 of $70.6 million ($45.9 million after income taxes) offset in part by gains on sales of marketable securities of $35.1 million ($22.8 million after income taxes).

 

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Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Our operating data for 2010 and 2011 is summarized below:

 

     Year Ended
December 31,
 
     2010      2011  

Net Production Data:

     

Natural gas (MMcf)

     68,973         90,593   

Oil (MBbls)

     715         838   

Natural gas equivalent (MMcfe)

     73,262         95,622   

Average Sales Price:

     

Oil ($/Bbl)

     $68.35         $95.73   

Natural gas ($/Mcf)

     $4.35         $3.91   

Average equivalent price ($/Mcfe)

     $4.77         $4.54   

Expenses ($ per Mcfe):

     

Production taxes

     $0.14         $0.04   

Gathering and transportation

     $0.24         $0.30   

Lease operating(1)

     $0.72         $0.48   

Depreciation, depletion and amortization(2)

     $2.91         $3.00   

 

 

(1) Includes ad valorem taxes.
(2) Represents depreciation, depletion and amortization of oil and gas properties only.

Oil and gas sales.    Our oil and gas sales increased $85.3 million (24%) in 2011 to $434.4 million from sales of $349.1 million in 2010. This increase resulted from higher natural gas production and higher prices realized for oil sales in 2011. Our production in 2011 increased by 31% over 2010’s production as production from new wells drilled in South Texas targeting the Eagle Ford shale and in North Louisiana targeting the Haynesville/Bossier shales exceeded declines from our existing producing properties. Prices realized for oil sales increased by 40% in 2011 as compared to 2010 while the average price we realized for natural gas sales decreased by 10% in 2011 as compared to 2010. During 2011 we drilled 87 wells (47.7 net to us), 62 of which were Haynesville or Bossier shale horizontal wells and 20 of which were Eagle Ford shale horizontal wells. At December 31, 2011 we had 23 wells (15.5 net to us) that were drilled in 2011 awaiting completion.

Production taxes.    Production taxes decreased $6.2 million (63%) to $3.7 million in 2011 from $9.9 million in 2010. Our Haynesville and Bossier shale wells, which comprise a large percentage of our production, qualify for exemption from certain state production taxes. The exempt wells together with the lower natural gas prices account for the decrease.

Gathering and transportation.    Gathering and transportation costs in 2011 increased $11.2 million (65%) to $28.5 million as compared to $17.3 million in 2010 due to the transportation costs related to the higher production from our Haynesville/Bossier shale properties in North Louisiana.

Lease operating expenses.    Our lease operating expenses, including ad valorem taxes, of $46.6 million in 2011 were $6.9 million or 13% lower than our operating expenses of $53.5 million in 2010. Our lease operating expense per Mcfe produced decreased by 33% to $0.48 per Mcfe in 2011 as compared to $0.72 per Mcfe in 2010. The decreases in lease operating expenses are primarily due to the sale of our higher operating cost properties in Mississippi in 2010.

Exploration expense.    We incurred $10.1 million in exploration expense in 2011 as compared to $2.6 million in 2010. Exploration expense in 2011 consisted of $9.8 million of impairments of unevaluated leasehold costs and $0.3 million for the acquisition of seismic data. Our 2010 exploration cost primarily related to costs incurred for the acquisition of seismic data.

 

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DD&A. DD&A of $290.8 million increased $77.0 million (36%) as compared to DD&A of $213.8 million in 2010. Our DD&A rate per Mcfe produced averaged $3.00 in 2011 as compared to $2.91 for 2010. The increase in DD&A primarily resulted from our 31% growth in production in 2011.

Impairment of oil and gas properties.    We recorded impairments to our oil and gas properties of $60.8 million and $0.2 million in 2011 and 2010, respectively. These impairments relate to fields where an impairment was indicated based on estimated future cash flows from the properties. The 2011 impairment is a result of lower anticipated natural gas prices.

General and administrative expenses.    General and administrative expense of $35.2 million for 2011 was 5% lower than general and administrative expense of $37.2 million for 2010. The decrease primarily reflects our lower personnel costs in 2011. Stock based compensation decreased by $2.4 million to $15.0 million in 2011 as compared to $17.4 million in 2010.

Interest expense.    Interest expense increased $13.2 million (45%) to $42.7 million in 2011 from interest expense of $29.5 million in 2010. The increase was primarily related to the increase in outstanding debt during 2011 including the issuance of $300.0 million in senior notes in March 2011. Average borrowings under our bank credit facility increased to $121.4 million in 2011 as compared to $70.0 million for 2010. The average interest rate on the outstanding borrowings under our credit facility of 2.2% in 2011 was unchanged from 2010. We capitalized interest of $13.2 million and $13.0 million in 2011 and 2010, respectively, which reduced interest expense. Interest expense in 2011 includes $1.1 million for the early retirement of our 6 7/8% senior notes which were due in March 2012.

Income taxes.    The benefit from income taxes increased in 2011 to $14.6 million from $4.8 million in 2010 due to the higher net loss in 2011. Our effective tax rate of 30% in 2011 and 20% in 2010 differed from the federal income tax rate of 35% primarily due to the effect of nondeductible compensation and state income taxes.

Net loss.    We reported a loss of $33.5 million for 2011 as compared to a loss of $19.6 million for 2010. The loss per share for 2011 was $0.73 on weighted average shares outstanding of 46.0 million as compared to a loss per share of $0.43 for 2010 on weighted average shares outstanding of 45.6 million. The loss in 2011 was primarily related to the impairments to proved and unproved properties in 2011 of $70.6 million ($45.9 million after income taxes) offset in part by gains on sales of marketable securities of $35.1 million ($22.8 million after income taxes). The loss in 2010 was primarily related to the loss on our divestiture of oil and gas properties in Mississippi of $25.8 million ($16.8 million after income taxes).

Liquidity and Capital Resources

Funding for our activities has historically been provided by our operating cash flow, debt or equity financings and asset dispositions. Our net cash provided by operating activities in 2012 totaled $262.2 million. Our other primary sources of funds in 2012 included $285.9 million of net proceeds from a senior notes offering and $204.4 million from sales of assets. In 2011, our net cash flow provided by operating activities totaled $284.9 million, while our other primary sources of funds included $293.4 million of net proceeds from a senior notes offering, $555.0 million of borrowings under our bank credit facility and $53.4 million of proceeds from sales of marketable securities. In 2010, our net cash flow provided by operating activities from continuing operations totaled $311.7 million. Our other primary source of funds in 2010 was $96.9 million of net proceeds from sales of oil and gas properties and marketable securities and $45.0 million of borrowings under our bank credit facility.

Our cash flow from operating activities in 2012 of $262.2 million represented a decrease of $22.7 million from our cash from operating activities of $284.9 million in 2011. Cash flow from

 

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operations excluding changes in working capital accounts of $261.3 million in 2012 decreased by $36.3 million or 12% as compared to $297.6 million in 2011 due to the lower revenues we received because of the decline in natural gas prices during 2012 which was partially offset by higher oil production. Our cash flow from operating activities in 2011 decreased by $26.8 million to $284.9 million as compared to $311.7 million in 2010 primarily due to changes in working capital at the end of 2011.

Our primary need for capital, in addition to funding our ongoing operations, relates to the acquisition, development and exploration of our oil and gas properties and the repayment of our debt. During 2012 our capital expenditures of $550.6 million decreased by $497.1 million as compared to 2011 capital expenditures of $1.0 billion due primarily to the acquisitions of proved and unproved properties we made in 2011. Capital expenditures in 2012 include $70.9 million spent to complete wells drilled in 2011. In 2011, our capital expenditures of $1.0 billion increased by $502.0 million as compared to 2010 capital expenditures of $545.7 million, mainly due to the acquisition of oil and gas properties in 2011.

Our annual capital expenditure activity is summarized in the following table:

 

     Year Ended December 31,  
     2010      2011      2012  
     (In thousands)  

Exploration and development:

        

Acquisitions of proved oil and gas properties

   $       $ 218,661       $ 3,235   

Acquisitions of unproved oil and gas properties

     134,728         255,699         29,677   

Developmental leasehold costs

     3,208         798         2,157   

Development drilling

     305,410         483,816         504,482   

Exploratory drilling

     85,140         82,028         5,317   

Workovers and recompletions

     5,648         6,516         3,728   
  

 

 

    

 

 

    

 

 

 
     534,134         1,047,518         548,596 (1) 

Other

     11,516         225         1,984   
  

 

 

    

 

 

    

 

 

 

Total

   $    545,650       $    1,047,743       $ 550,580 (1) 
  

 

 

    

 

 

    

 

 

 

 

 

  (1) Excludes reimbursements from joint venture partner for preformation well costs of $23.8 million.

The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments except for contracted drilling and completion services. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. We currently expect to spend approximately $445.0 million for development and exploration projects and lease acquisitions in 2013, which will be funded primarily by cash flows from operating activities, proceeds from asset sales and borrowings under our credit facility. Our operating cash flow and, therefore, our capital expenditures are highly dependent on oil and natural gas prices and, in particular, natural gas prices.

We do not have a specific acquisition budget for 2013 because the timing and size of acquisitions are unpredictable. Smaller acquisitions will generally be funded from operating cash flow. With respect to significant acquisitions, we intend to use borrowings under our bank credit facility, or other debt or equity financings to the extent available, to finance such acquisitions. The availability and attractiveness of these sources of financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, oil and natural gas prices and other market conditions. Lack of access to the debt or equity markets due to general economic conditions could impede our ability to complete acquisitions.

We have a $850.0 million bank credit facility with Bank of Montreal, as the administrative agent. The bank credit facility is a five-year revolving credit commitment that matures on November 30, 2015.

 

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Indebtedness under the bank credit facility is secured by all of our and our wholly owned subsidiaries’ assets and is guaranteed by all of our wholly owned subsidiaries. The bank credit facility is subject to borrowing base availability, which is redetermined semiannually based on the banks’ estimates of the future net cash flows of our oil and natural gas properties. As of December 31, 2012, the borrowing base was $570.0 million, $130.0 million of which was available. The borrowing base may be affected by the performance of our properties and changes in oil and natural gas prices. The determination of the borrowing base is at the sole discretion of the administrative agent and the bank group. Borrowings under the bank credit facility bear interest, based on the utilization of the borrowing base, at our option at either (1) LIBOR plus 1.75% to 2.75% or (2) the base rate (which is the higher of the administrative agent’s prime rate, the federal funds rate plus 0.5% or 30 day LIBOR plus 1.0%) plus 0.75% to 1.75%. A commitment fee of 0.5% is payable on the unused borrowing base. The bank credit facility contains covenants that, among other things, restrict the payment of cash dividends in excess of $50.0 million, limit the amount of consolidated debt that we may incur and limit our ability to make certain loans and investments. The only financial covenants are the maintenance of a ratio of current assets, including the availability under the bank credit facility, to current liabilities and maintenance of a leverage ratio. We were in compliance with these covenants as of December 31, 2012.

We have $300.0 million of 8 3/8% senior notes outstanding which are due October 15, 2017, $300.0 million of 7 3/4% senior notes outstanding which are due April 1, 2019 and $300.0 million of 9 1/2% senior notes outstanding which are due June 15, 2020. All senior notes have semi-annual interest payment obligations, are unsecured obligations and are guaranteed by all of our material subsidiaries.

On January 1, 2011, we had $172.0 million in principal amount of 6 7/8% senior notes outstanding due in 2012 (the “2012 Notes”). We redeemed all of the 2012 Notes in 2011 for $172.4 million. The early extinguishment of the 2012 Notes resulted in a loss of $1.1 million. This loss is comprised of the premium paid for the redemption of the 2012 Notes, the costs incurred related to the tender offer, and the write-off of unamortized debt issuance costs related to the 2012 Notes.

We believe that our cash flow from operations and available borrowings under our bank credit facility will be sufficient to fund our operations and future growth as contemplated under our current business plan. However, if our plans or assumptions change or if our assumptions prove to be inaccurate, we may be required to seek additional capital. We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms.

The following table summarizes our aggregate liabilities and commitments by year of maturity:

 

     2013     2014     2015     2016     2017     Thereafter     Total  
     (In thousands)  

Bank credit facility

   $      $      $ 440,000      $      $      $      $ 440,000   

8 3/8% senior notes

                                 300,000               300,000   

7 3/4% senior notes

                                        300,000        300,000   

9 1/2% senior notes

                                        300,000        300,000   

Interest on debt

     88,843        88,843        87,846        76,875        71,641        99,126        513,174   

Operating leases

     1,983        2,012        2,038        1,994        2,021        6,740        16,788   

Natural gas transportation agreements

     9,416        6,840        4,074        1,696        1,277        1,968        25,271   

Contracted drilling services

     31,149        20,112        14,030                             65,291   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   $      131,391      $       117,807      $       547,988      $      80,565      $       374,939      $      707,834      $  1,960,524   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Future interest costs are based upon the effective interest rates of our outstanding senior notes and the December 31, 2012 rate for our bank credit facility.

 

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We have obligations to incur future payments for dismantlement, abandonment and restoration costs of oil and gas properties. These payments are currently estimated to be incurred primarily after 2017. We record a separate liability for the fair value of these asset retirement obligations, which totaled $18.0 million as of December 31, 2012.

Federal Taxation

At December 31, 2012 we had U.S. federal net operating loss carryforwards of approximately $192.3 million and Louisiana state net operating loss carryforwards of approximately $536.4 million. Utilization of $36.9 million of our U.S. federal net operating loss carryforwards is limited to approximately $1.1 million per year pursuant to a prior change of control of an acquired company and a valuation allowance of $23.0 million has been established for the estimated U.S. federal net operating loss carryforwards that will not be utilized. Realization of the remaining U.S. federal net operating loss carryforwards requires Comstock to generate taxable income within the carryforward period. A valuation allowance of $288.0 million has been established against our Louisiana state net operating loss carryforwards due to the uncertainty of generating taxable income in the state of Louisiana prior to the expiration of the carryforward period.

Our federal income tax returns for the years subsequent to December 31, 2007 remain subject to examination. Our income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2007. We currently believe that our significant filing positions are highly certain and that all of our significant income tax filing positions and deductions would be sustained upon audit or the final resolution would not have a material effect on our consolidated financial statements. Therefore, we have not established any significant reserves for uncertain tax positions. Interest and penalties resulting from audits by tax authorities have been immaterial and are included in the provision for income taxes in the consolidated statements of operations.

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and use assumptions that can affect the reported amounts of assets, liabilities, revenues or expenses.

Successful efforts accounting.    We are required to select among alternative acceptable accounting policies. There are two generally acceptable methods for accounting for oil and gas producing activities. The full cost method allows the capitalization of all costs associated with finding oil and natural gas reserves, including certain general and administrative expenses. The successful efforts method allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration projects. Costs related to exploration that are not successful are expensed when it is determined that commercially productive oil and gas reserves were not found. We have elected to use the successful efforts method to account for our oil and gas activities and we do not capitalize any of our general and administrative expenses.

Oil and natural gas reserve quantities.    The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. The determination of whether impairments should be recognized on our oil and gas properties is also dependent on these estimates, as well as estimates of probable reserves. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve

 

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estimates are to some degree imprecise, the quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas prices may all differ materially from those assumed in these estimates. The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Any future downward revisions could adversely affect our financial condition, our borrowing ability, our future prospects and the value of our common stock.

Impairment of oil and gas properties.    We evaluate our properties on a field area basis for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Expected future cash flows are determined using estimated future prices based on market based forward prices applied to projected future production volumes. The projected production volumes are based on the property’s proved and risk adjusted probable oil and natural gas reserve estimates at the end of the period. The estimated future cash flows that we use in our assessment of the need for an impairment are based on market prices for oil and natural gas for the next three years, with a 5% escalation of prices for subsequent years. Prices are not escalated to levels that exceed observed historical market prices. Costs are also assumed to escalate at a rate that is based on our historical experience, currently estimated at 2% per annum. The oil and natural gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of the average first day of the month historical price for the year. To the extent that oil and natural gas prices do not increase as anticipated in these assumptions or costs increase at a greater rate than assumed, certain of our evaluated properties which presently have a carrying value of $463.0 million may require impairment in the future. The amount of such impairments would be based on the write down of these properties to their then current estimated fair value. In addition to these properties, other properties may become impaired due to downward revisions in reserve or price estimates or for other reasons.

Asset retirement obligations.    We have obligations to remove tangible equipment and facilities and to restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of any surface equipment used in production operations. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Stock-based compensation.    We follow the fair value based method in accounting for equity-based compensation. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period.

Related Party Transactions

In recent years, we have not entered into any material transactions with our officers or directors apart from the compensation they are provided for their services. We also have not entered into any business transactions with our significant stockholders or any other related parties.

 

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Oil and Natural Gas Prices

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil, the foreign supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on our oil and natural gas production in 2012, a $1.00 change in the price per barrel of oil would have resulted in a change in our cash flow for such period by approximately $0.6 million and a $0.10 change in the price per Mcf of natural gas would have changed our cash flow by approximately $8.0 million.

We have entered into oil price swap agreements covering 2.2 million barrels of our expected 2013 oil production which fix the NYMEX West Texas Intermediate (“WTI”) price at $98.67 per barrel. As of December 31, 2012, our outstanding oil swap agreements had a fair value of $11.7 million. The change in the fair value of our oil swaps that would result from a 10% change in commodities prices at December 31, 2012 would be $12.9 million. Such a change in fair value could be a gain or a loss depending on whether prices increase or decrease.

Interest Rates

At December 31, 2012, we had $1.3 billion of long-term debt. Of this amount, $300.0 million bears interest at 8 3/8%, $300.0 million bears interest at a fixed rate of 7 3/4%, and $300.0 million bears interest at 9 1/2%. The fair market value of our fixed rate debt as of December 31, 2012 was $942.0 million based on the market price of approximately 107% of the face amount. At December 31, 2012, we had $440.0 million outstanding under our bank credit facility, which is subject to variable rates of interest. Borrowings under the bank credit facility bear interest at a fluctuating rate that is tied to LIBOR or the corporate base rate, at our option. Any increase in these interest rates would have an adverse impact on our results of operations and cash flow. Based on borrowings outstanding at December 31, 2012, a 100 basis point change in interest rates would change our annual interest expense on our variable rate debt by approximately $4.4 million. We had no interest rate derivatives outstanding during 2012 or at December 31, 2012.

 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our consolidated financial statements are included on pages F-1 to F-34 of this report.

We have prepared these financial statements in conformity with generally accepted accounting principles. We are responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary for us to make informed estimates and judgments based on currently available information on the effects of certain events and transactions.

 

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Our independent public accountants, Ernst & Young LLP, are engaged to audit our financial statements and to express an opinion thereon. Their audit is conducted in accordance with auditing standards generally accepted in the United States to enable them to report whether the financial statements present fairly, in all material respects, our financial position and results of operations in accordance with accounting principles generally accepted in the United States.

The audit committee of our board of directors is comprised of three directors who are not our employees. This committee meets periodically with our independent public accountants and management. Our independent public accountants have full and free access to the audit committee to meet, with and without management being present, to discuss the results of their audits and the quality of our financial reporting.

 

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

 

ITEM 9A.     CONTROLS AND PROCEDURES

Evaluation of Controls and Procedures.    Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act) are designed to provide reasonable assurance that information required to be disclosed in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

We performed an evaluation of the effectiveness of our disclosure controls and procedures as of December 31, 2012. The evaluation was performed with the participation of senior management of each business segment and key corporate functions, and under the supervision of the Chief Executive Officer and Chief Financial Officer. As described below, management has identified a material weakness in our internal control over financial reporting, which is an integral component of our disclosure controls and procedures. As a result of this material weakness, we concluded that our disclosure controls and procedures were not effective as of December 31, 2012.

As part of the preparation of our financial statements for the year ended December 31, 2012, we undertook a review of our accounting for oil price derivative financial instruments. We use derivative financial instruments as a means of reducing our exposure to fluctuating commodity prices for oil and natural gas. During the quarters ended March 31, 2012, June 30, 2012 and September 30, 2012, we applied cash flow hedge accounting for our derivative financial instruments as provided for in Accounting Standards Codification Topic 815, Derivatives and Hedging (“ASC 815”). Accordingly, we included changes from period to period in the fair value of derivative financial instruments classified as cash flow hedges as increases or decreases to Accumulated Other Comprehensive Income (“AOCI”). In order to qualify for cash flow hedge accounting treatment, specific standards and contemporaneous documentation requirements must be met. We believed that we had met those requirements and that our hedge accounting treatment was permitted under ASC 815. However, in connection with preparing our 2012 Annual Report, and based upon discussions with Ernst & Young, LLP, our independent public accounting firm, we determined that our hedge documentation was not completed in a timely manner, and as a result our commodity derivative financial instruments did not qualify for hedge accounting treatment under ASC 815.

 

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In February 2013 the Audit Committee of our Board of Directors concluded that our previously issued consolidated financial statements contained a material error with respect to accounting for derivative financial instruments, and should be restated. Accordingly, we are restating the consolidated financial statements for each of the three months ended March 31, 2012, June 30, 2012 and September 30, 2012 to reflect the change in the fair value of our derivative financial instruments, as a separate component of other income (expenses) in our statements of operations rather than as a component of AOCI. We are also reclassifying the realized gains and losses from our derivative financial instruments as a component of other income (expenses) rather than as a component of oil and gas sales.

We have concluded, based on the circumstances involving the restatement of the financial statements for the three months ended March 31, 2012, June 30, 2012 and September 30, 2012, that a material weakness in internal control over financial reporting existed at December 31, 2012 with respect to the design of our controls over the timeliness of documentation required to designate our derivative financial instruments as cash flow hedges in accordance with ASC 815.

Management’s Report on Internal Control over Financial Reporting.    We are responsible for establishing and maintaining adequate internal control over financial reporting for the company. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, we conducted an assessment, including testing, using the criteria in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Our system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A “material weakness” is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness relating to the accounting for derivative financial instruments resulted in misstatements of the aforementioned accounts and disclosures that resulted in material misstatements in our interim financial statements. Because of this material weakness, management has concluded that we did not maintain effective internal control over financial reporting as of December 31, 2012. Our internal control over financial reporting as of December 31, 2012, has been audited by Ernst & Young, LLP, an independent registered public accounting firm, as stated in their report included herein.

Plans for Remediation of the Material Weakness.    In response to the material weakness, we did not account for derivative financial instruments as cash flow hedges under ASC 815 in the fourth quarter of 2012 and are recognizing realized gains and losses and changes in the fair value of our derivative financial instruments in current earnings as separate components of other income (losses). We are developing a remediation plan to address the material weakness described above. The remediation plan will include designing and implementing a control framework over entering into derivative financial instruments to ensure that our accounting for derivative financial instruments which was affected by the material control weakness is appropriate. The remediation plan will involve key leaders from across the organization, including the Chief Executive Officer, the Chief Financial Officer and our internal auditors. We will report quarterly and as needed to the Audit Committee of our Board of Directors on the progress made toward completion of the remediation plan.

We continue to monitor the effectiveness of our internal control over financial reporting with respect to our accounting for derivatives which was affected by the material weakness described above. We will

 

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perform additional procedures prescribed by management, including the use of manual mitigating control procedures, and we will employ any additional tools and resources deemed necessary to ensure that our financial statements continue to be fairly stated in all material respects.

Changes in Internal Control over Financial Reporting.    Except as noted above with respect to our discontinuation of cash flow hedge accounting in the fourth quarter of 2012, there were no changes in our internal control over financial reporting during the quarter ended December 31, 2012 that materially affected or are reasonably likely to materially affect our internal control over financial reporting. However, as described above under “Plans for Remediation of Material Weaknesses,” we have initiated a process to improve the control environment and to remedy the control weakness described herein.

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Comstock Resources, Inc.

We have audited Comstock Resources, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Comstock Resources, Inc. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment. Management has identified a material weakness in controls related to the Company’s accounting for derivative financial instruments at December 31, 2012. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Comstock Resources, Inc. and subsidiaries as of December 31, 2011 and 2012, and the related consolidated statements of operations, comprehensive loss, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2012. This material weakness was considered in determining the nature, timing and extent of audit tests applied in our audit of the 2012 financial statements and this report does not affect our report dated February 28, 2013, which expressed an unqualified opinion on those financial statements.

In our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Comstock Resources, Inc. and subsidiaries have not maintained effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

Dallas, Texas

February 28, 2013

 

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ITEM 9B.     OTHER INFORMATION

None.

PART III

 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item is incorporated herein by reference to “Business — Directors and Executive Officers” in this Form 10-K and to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2012.

Code of Ethics.    We have adopted a Code of Business Conduct and Ethics that is applicable to all of our directors, officers and employees as required by New York Stock Exchange rules. We have also adopted a Code of Ethics for Senior Financial Officers that is applicable to our Chief Executive Officer and Senior Financial Officers. Both the Code of Business Conduct and Ethics and Code of Ethics for Senior Financial Officers may be found on our website at www.comstockresources.com. Both of these documents are also available, without charge, to any stockholder upon request to: Comstock Resources, Inc., Attn: Investor Relations, 5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034, (972) 668-8800. We intend to disclose any amendments or waivers to these codes that apply to our Chief Executive Officer and senior financial officers on our website in accordance with applicable SEC rules. Please see the definitive proxy statement for our 2013 annual meeting, which will be filed with the SEC within 120 days of December 31, 2012, for additional information regarding our corporate governance policies.

 

ITEM 11. EXECUTIVE COMPENSATION

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2012.

 

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table summarizes certain information regarding our equity compensation plans as of December 31, 2012:

 

    

Number of securities to be
issued upon exercise of
outstanding options, warrants
and rights

  

Weighted average exercise
price of outstanding options,
warrants and rights

  

Number of securities authorized
for future issuance under
equity compensation plans
(excluding outstanding
options, warrants and rights)

Equity compensation plans approved by stockholders

   845,695(1)    $38.36(2)    1,607,372

 

 

  (1) Includes performance share unit awards equivalent to 688,545 shares that would be issuable based upon achievement of the maximum awards under the terms of the performance share unit awards.
  (2) Price reflects the grant date fair value of 157,150 stock options that are outstanding; excludes performance share units for which the price cannot be determined until the performance targets are met.

We do not have any equity compensation plans that were not approved by stockholders.

Further information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2012.

 

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTORS INDEPENDENCE

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2012.

 

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2012.

PART IV

 

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements:

1. The following consolidated financial statements and notes of Comstock Resources, Inc. are included on Pages F-2 to F-34 of this report:

 

Report of Independent Registered Public Accounting Firm

     F-2   

Consolidated Balance Sheets as of December 31, 2011 and 2012

     F-3   

Consolidated Statements of Operations for the Years Ended December 31, 2010, 2011 and 2012

     F-4   

Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2010, 2011 and 2012

     F-5   

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2010, 2011 and 2012

     F-6   

Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2011 and 2012

     F-7   

Notes to Consolidated Financial Statements

     F-8   

2.  All financial statement schedules are omitted because they are not applicable, or are immaterial or the required information is presented in the consolidated financial statements or the related notes.

(b)  Exhibits:

The exhibits to this report required to be filed pursuant to Item 15 (c) are listed below.

 

Exhibit No.

  

Description

3.1(a)    Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 to our Annual Report on Form 10-K for the year ended December 31, 1995).
3.1(b)    Certificate of Amendment to the Restated Articles of Incorporation dated July 1, 1997 (incorporated by reference to Exhibit 3.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 1997).
3.2    Certificate of Amendment to the Restated Articles of Incorporation dated May 19, 2009 (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-3 dated October 5, 2009).

 

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Exhibit No.

  

Description

3.3    Bylaws (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated November 8, 2011).
4.1    Indenture dated February 25, 2004 between Comstock, the guarantors and The Bank of New York Trust Company, N.A., Trustee for debt securities issued by Comstock Resources, Inc. (incorporated by reference to Exhibit 4.6 to our Annual Report on Form 10-K for the year ended December 31, 2003).
4.2    Indenture dated October 9, 2009 between Comstock, the guarantors and The Bank of New York Mellon Trust Company, N.A., Trustee for debt securities (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K dated October 9, 2009).
4.3    First Supplemental Indenture, dated October 9, 2009 between Comstock, the guarantors and The Bank of New York Mellon Trust Company, N.A., Trustee for the 8 3/8% Senior Notes due 2017 (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K dated October 9, 2009).
4.4    Second Supplemental Indenture dated April 30, 2010 between Comstock, the guarantors and The Bank of New York Mellon Trust Company, N.A., Trustee for the 8 3/8 Senior Notes due 2017 (incorporated by reference to our Annual Report on Form 10-K for the year ended December 31, 2010).
4.5    Third Supplemental Indenture dated March 14, 2011 between Comstock, the guarantors and The Bank of New York Mellon Trust Company, N.A., for the 7 3/4% Senior Notes due 2019 (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K dated March 14, 2011).
4.6    Fourth Supplemental Indenture dated June 5, 2012 between Comstock, the guarantors and The Bank of New York Mellon Trust Company, N.A., for the 9 1/2% Senior Notes due 2020 (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K dated June 7, 2012).
10.1#    Employment Agreement dated December 22, 2008 by and between Comstock and M. Jay Allison (incorporated by reference to Exhibit 99.1 to our Current Report on Form 8-K dated December 22, 2008).
10.2#    Employment Agreement dated December 22, 2008 by and between Comstock and Roland O. Burns (incorporated by reference to Exhibit 99.2 to our Current Report on Form 8-K dated December 22, 2008).
10.3#    Comstock Resources, Inc. 2009 Long-term Incentive Plan (incorporated by reference to Exhibit 99 to our Registration Statement on Form S-8 dated May 19, 2009).
10.4*#    First Amendment to the Comstock Resources, Inc. 2009 Long-term Incentive Plan.
10.5#    Form of Restricted Stock Agreement under the Comstock Resources, Inc. 2009 Long-term Incentive Plan (incorporated by reference to Exhibit 10.4 to our Annual Report on Form 10-K for the year ended December 31, 2009).
10.6*#    Form of Performance Share Unit Agreement under the Comstock Resources, Inc. 2009 Long-term Incentive Plan.
10.7    Lease between Stonebriar I Office Partners, Ltd. and Comstock Resources, Inc. dated May 6, 2004 (incorporated by reference to Exhibit 10.24 to our Annual Report on Form 10-K for the year ended December 31, 2004).
10.8    First Amendment to the Lease Agreement dated August 25, 2005, between Stonebriar I Office Partners, Ltd. and Comstock Resources, Inc. (incorporated by reference to Exhibit 10.20 to our Annual Report on Form 10-K for the year ended December 31, 2005).

 

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Exhibit No.

  

Description

10.9    Second Amendment to the Lease Agreement dated October 15, 2007 between Stonebriar I Office Partners, Ltd. and Comstock Resources, Inc. (incorporated by reference to Exhibit 10.10 to our Annual Report on Form 10-K for the year ended December 31, 2008).
10.10    Third Amendment to the Lease Agreement dated September 30, 2008 between Stonebriar I Office Partners, Ltd. and Comstock Resources, Inc. (incorporated by reference to Exhibit 10.11 to our Annual Report on Form 10-K for the year ended December 31, 2008).
10.11    Fourth Amendment to the Lease Agreement dated May 8, 2009 between Stonebriar I Office Partners, Ltd. and Comstock Resources, Inc. (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2009).
10.12    Fifth Amendment to the Lease Agreement dated June 15, 2011 between Stonebriar I Office Partners, Ltd. and Comstock Resources, Inc. (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2011).
10.13    Third Amended and Restated Credit Agreement, dated November 30, 2010, among Comstock Resources, Inc., as the borrower, the lenders from time to time thereto, Bank of Montreal, as administrative agent and issuing bank, Bank of America, N.A., as syndication agent and Comerica, JP Morgan Chase Bank, N.A., and Union Bank, N.A., as co-documentation agents (incorporated by reference to Exhibit 10.10 to our Annual Report on Form 10-K for the year ended December 31, 2010).
10.14    Assignment and First Amendment to Third Amended and Restated Credit Agreement dated October 31, 2011 (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2011).
10.15    Second Amendment and Waiver to Third Amended and Restated Credit Agreement, dated December 29, 2011, among Comstock Resources, Inc., as the borrower, the lenders from time to time thereto, and Bank of Montreal, as administrative agent (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K dated December 29, 2011).
10.16    Third Amendment to Third Amended and Restated Credit Agreement, dated October 29, 2012, among Comstock Resources, Inc., as the borrower, the lenders from time to time thereto, and Bank of Montreal, as administrative agent (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2012).
10.17*    Fourth Amendment to Third Amended and Restated Credit Agreement dated February 8, 2013, among Comstock Resources, Inc., as the borrower, the lenders from time to time thereto, and Bank of Montreal, as administrative agent.
10.18    Base Contract for Sale and Purchase of Natural Gas between Comstock Oil & Gas-Louisiana, LLC and BP Energy Company dated November 7, 2008, as amended by Third Amended and Restated Special Provisions dated January 5, 2010 (incorporated by reference to Exhibit 10.14 to our Annual Report on Form 10-K for the year ended December 31, 2009).
10.19    Purchase and Sale Agreement dated December 5, 2011 among Eagle Oil & Gas Co., certain other sellers and Comstock Oil & Gas, LP (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K dated December 5, 2011).
21*    Subsidiaries of the Company.
23.1*    Consent of Ernst & Young LLP.
23.2*    Consent of Independent Petroleum Engineers.
31.1*    Chief Executive Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*    Chief Financial Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.

 

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Exhibit No.

  

Description

32.1+    Chief Executive Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2+    Chief Financial Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*    Report of Independent Petroleum Engineers on Proved Reserves as of December 31, 2012.
101.INS*    XBRL Instance Document
101.SCH*    XBRL Schema Document
101.CAL*    XBRL Calculation Linkbase Document
101.LAB*    XBRL Labels Linkbase Document
101.PRE*    XBRL Presentation Linkbase Document
101.DEF*    XBRL Definition Linkbase Document

 

 

    * Filed herewith.
    + Furnished herewith.
    # Management contract or compensatory plan document.

 

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

COMSTOCK RESOURCES, INC.
By:  

/s/    M. JAY ALLISON

 

M. Jay Allison

President and Chief Executive Officer

(Principal Executive Officer)

Date: February 28, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

/s/    M. JAY ALLISON

M. Jay Allison

  

President, Chief Executive Officer and

Chairman of the Board of Directors

(Principal Executive Officer)

  February 28, 2013

/s/    ROLAND O. BURNS

Roland O. Burns

  

Senior Vice President, Chief Financial

Officer, Secretary, Treasurer and Director (Principal Financial and Accounting Officer)

  February 28, 2013

/s/    DAVID K. LOCKETT

David K. Lockett

   Director   February 28, 2013

/s/    CECIL E. MARTIN, JR.

Cecil E. Martin, Jr.

   Director   February 28, 2013

/s/    FREDERIC D. SEWELL

Frederic D. Sewell

   Director   February 28, 2013

/s/    DAVID W. SLEDGE

David W. Sledge

   Director   February 28, 2013

/s/    NANCY E. UNDERWOOD

Nancy E. Underwood

   Director   February 28, 2013

 

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COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

FINANCIAL STATEMENTS

 

 

 

 

INDEX

 

 

 

Report of Independent Registered Public Accounting Firm

     F-2   

Consolidated Balance Sheets as of December 31, 2011 and 2012

     F-3   

Consolidated Statements of Operations for the Years Ended December 31, 2010, 2011 and 2012

     F-4   

Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2010, 2011 and 2012

     F-5   

Consolidated Statements of Stockholders’ Equity for the Years Ended December  31, 2010, 2011 and 2012

     F-6   

Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2011 and 2012

     F-7   

Notes to Consolidated Financial Statements

     F-8   

 

F-1


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Comstock Resources, Inc.

We have audited the accompanying consolidated balance sheets of Comstock Resources, Inc. and subsidiaries as of December 31, 2011 and 2012, and the related consolidated statements of operations, comprehensive loss, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Comstock Resources, Inc. and subsidiaries at December 31, 2011 and 2012, and the consolidated results of their operations and cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Comstock Resources, Inc.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2013 expressed an adverse opinion thereon.

/s/    ERNST & YOUNG LLP

Dallas, Texas

February 28, 2013

 

F-2


Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

As of December 31, 2011 and 2012

 

     December 31,  
     2011     2012  
     (In thousands)  
ASSETS   

Cash and Cash Equivalents

   $ 8,460      $ 4,471   

Accounts Receivable:

    

Oil and gas sales

     47,082        36,150   

Joint interest operations

     6,651        5,608   

Marketable Securities

     47,642        12,312   

Derivative Financial Instruments

     459        11,651   

Other Current Assets

     2,796        6,954   
  

 

 

   

 

 

 

Total current assets

     113,090        77,146   

Property and Equipment:

    

Unevaluated oil and gas properties

     369,096        263,652   

Oil and gas properties, successful efforts method

     3,476,146        3,779,716   

Other

     18,062        19,301   

Accumulated depreciation, depletion and amortization

     (1,353,459     (1,592,616
  

 

 

   

 

 

 

Net property and equipment

     2,509,845        2,470,053   

Other Assets

     16,949        19,944   
  

 

 

   

 

 

 
   $ 2,639,884      $ 2,567,143   
  

 

 

   

 

 

 
LIABILITIES AND STOCKHOLDERS’ EQUITY   

Accounts Payable

   $ 94,041      $ 86,346   

Deferred Income Taxes Payable

     7,664        5,340   

Accrued Expenses

     85,502        47,372   
  

 

 

   

 

 

 

Total current liabilities

     187,207        139,058   

Long-term Debt

     1,196,908        1,324,383   

Deferred Income Taxes Payable

     201,705        149,901   

Reserve for Future Abandonment Costs

     13,997        17,994   

Other Non-Current Liabilities

     2,442        2,273   
  

 

 

   

 

 

 

Total liabilities

     1,602,259        1,633,609   

Commitments and Contingencies

    

Stockholders’ Equity:

    

Common stock—$0.50 par, 75,000,000 shares authorized, 48,125,296 and 48,408,734 shares issued and outstanding at December 31, 2011 and 2012, respectively

     24,063        24,204   

Additional paid-in capital

     468,709        480,595   

Accumulated other comprehensive income

     20,476        4,418   

Retained earnings

     524,377        424,317   
  

 

 

   

 

 

 

Total stockholders’ equity

     1,037,625        933,534   
  

 

 

   

 

 

 
   $ 2,639,884      $ 2,567,143   
  

 

 

   

 

 

 

 

The accompanying notes are an integral part of these statements.

 

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COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

For the Years Ended December 31, 2010, 2011 and 2012

 

     2010     2011     2012  
     (In thousands, except per share amounts)  

Oil and gas sales

   $  349,141      $  434,367      $ 431,923   

Gain on sale of oil and gas properties

                   24,271   
  

 

 

   

 

 

   

 

 

 

Total revenues

     349,141        434,367        456,194   
  

 

 

   

 

 

   

 

 

 

Operating expenses:

      

Production taxes

     9,894        3,670        14,021   

Gathering and transportation

     17,256        28,491        27,312   

Lease operating

     53,525        46,552        60,620   

Exploration

     2,605        10,148        61,449   

Depreciation, depletion and amortization

     213,809        290,776        365,286   

General and administrative, net

     37,200        35,172        33,798   

Impairment of oil and gas properties

     224        60,817        25,368   

Loss on sale of oil and gas properties

     26,632        57          
  

 

 

   

 

 

   

 

 

 

Total operating expenses

     361,145        475,683        587,854   
  

 

 

   

 

 

   

 

 

 

Operating loss

     (12,004     (41,316     (131,660

Other income (expenses):

      

Gain on sale of marketable securities

     16,529        35,118        26,621   

Realized gain from derivatives

                   9,766   

Unrealized gain from derivatives

                   11,490   

Other income

     499        790        944   

Interest expense

     (29,456     (42,688     (64,575
  

 

 

   

 

 

   

 

 

 

Total other income (expenses)

     (12,428     (6,780     (15,754
  

 

 

   

 

 

   

 

 

 

Loss before income taxes

     (24,432     (48,096     (147,414

Benefit from income taxes

     4,846        14,624        47,354   
  

 

 

   

 

 

   

 

 

 

Net loss

   $ (19,586   $ (33,472   $ (100,060
  

 

 

   

 

 

   

 

 

 

Net loss per share:

      

Basic

   $ (0.43   $ (0.73   $ (2.16
  

 

 

   

 

 

   

 

 

 

Diluted

   $ (0.43   $ (0.73   $ (2.16
  

 

 

   

 

 

   

 

 

 

Weighted average shares outstanding:

      

Basic

     45,561        45,997        46,422   
  

 

 

   

 

 

   

 

 

 

Diluted

     45,561        45,997        46,422   
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these statements.

 

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COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

For the Years Ended December 31, 2010, 2011 and 2012

 

     2010     2011     2012  
     (In thousands)  

Net loss

   $  (19,586   $  (33,472   $ (100,060

Unrealized hedging gains, net of provision for (benefit from)
income taxes of $—, $161 and $(161)

            298        (298

Net change in unrealized gains and losses on marketable securities, net of benefit from (provision for) income taxes of ($923), $6,543 and $8,487

     1,711        (12,152     (15,760
  

 

 

   

 

 

   

 

 

 

Other comprehensive income (loss)

     1,711        (11,854     (16,058
  

 

 

   

 

 

   

 

 

 

Comprehensive loss

   $ (17,875   $ (45,326   $ (116,118
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these statements.

 

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Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

For the Years Ended December 31, 2010, 2011 and 2012

 

     Common
Shares
     Common
Stock-
Par Value
     Additional
Paid-in
Capital
    Retained
Earnings
    Accumulated
Other

Comprehensive
Income
    Total  
     (In thousands)  

Balance at December 31, 2009

        47,104       $ 23,552       $ 434,505      $ 577,435      $ 30,619      $  1,066,111   

Exercise of stock options

        184         92         1,335                      1,427   

Stock-based compensation

        418         209         17,168                      17,377   

Excess income taxes from stock-based compensation

                        1,491                      1,491   

Net loss

                               (19,586            (19,586

Other comprehensive income

                                      1,711        1,711   
  

 

  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2010

        47,706         23,853         454,499        557,849        32,330        1,068,531   

Stock-based compensation

        419         210         14,822                      15,032   

Excess income taxes from stock-based compensation

                        (612                   (612

Net loss

                               (33,472            (33,472

Other comprehensive loss

                                      (11,854     (11,854
  

 

  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2011

        48,125         24,063         468,709        524,377        20,476        1,037,625   

Stock-based compensation

        284         141</