COMSTOCK RESOURCES INC - Annual Report: 2011 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

Commission File No. 001-03262

COMSTOCK RESOURCES, INC.

(Exact name of registrant as specified in its charter)

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:

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):

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 27, 2012, there were 48,121,346 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, 2011 (the last business day of the registrant’s most recently completed second fiscal quarter), was $1.3 billion.

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.

COMSTOCK RESOURCES, INC.

ANNUAL REPORT ON FORM 10-K

For the Fiscal Year Ended December 31, 2011

CONTENTS

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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:

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:

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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.

“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.

“MMBtu” means one million British thermal units.

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

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

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“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 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.

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“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

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 1.3 Tcfe with an estimated PV 10 Value of $1.5 billion as of December 31, 2011 and a standardized measure of discounted future net cash flows of $1.1 billion. Our consolidated proved oil and natural gas reserve base is 85% natural gas and 15% crude oil. Our proved reserves are 46% developed on a Bcfe basis as of December 31, 2011.

Our proved reserves at December 31, 2011 and our 2011 average daily production are summarized below:

Strengths

High Quality Properties.    Our operations are focused in three primary operating areas, the East Texas/North Louisiana, South Texas and West Texas regions. Our properties have an average reserve life of approximately 13.7 years and have extensive development and exploration potential. We have a substantial acreage position in our East Texas/North Louisiana region in the Haynesville or Bossier shale resource play where we have identified 96,090 acres (81,824 net to us) prospective for Haynesville or Bossier shale development. We also have 35,335 acres (27,856 net to us) in South Texas which are prospective for development of the Eagle Ford shale. In 2011 we acquired 89,883 acres (55,466 net to us) in West Texas which are prospective for development of the Wolfcamp shale.

Successful Exploration and Development Program.    In 2011 we spent $829.1 million on exploration and development activities. We drilled 87 wells (47.7 net to us) in 2011 at a cost of $436.3 million and we spent $129.5 million to complete 34 wells that were drilled in 2010. We spent $255.7 million to acquire additional exploratory leases and $0.3 million to acquire seismic data. We also spent $7.3 million for recompletions, workovers, abandonment, production facilities and developmental leasehold. Our drilling activities in 2011 added 228.3 Bcfe to our proved reserves and increased our production by 31% in 2011.

Efficient Operator.    We operate 88% of our proved oil and natural gas reserve base as of December 31, 2011. 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. In 2011, we acquired 164 Bcfe of proved oil and natural gas reserves for $218.7 million. 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. In late 2007 we identified the potential in our largest operating region, East Texas/North Louisiana, to explore for natural gas in the Haynesville shale, which was below the Cotton Valley, Hosston and Travis Peak sand formations that we have been developing. We drilled eight pilot wells in 2007 and 2008 to evaluate the prospectivity of the Haynesville shale. We undertook an active leasing program to acquire additional acreage in areas we believed would be prospective in the Haynesville shale and spent $238.0 million from 2007 through 2011 to increase our acreage position to 96,090 acres (81,824 net to us) with Haynesville or Bossier shale potential. We started the commercial development of the Haynesville shale in late 2008 and have drilled 180 successful horizontal wells (105.6 net to us) through 2011. In 2011, we drilled 62 Haynesville and Bossier shale horizontal wells (28.0 net to us) which added 139.9 Bcfe to our proved reserves in 2011. With the low natural gas price outlook in 2012, we plan to reduce our natural gas focused drilling. We have budgeted to spend $106.8 million in 2012 to complete 14 Haynesville and Bossier shale horizontal wells (9.8 net to us) that were drilled in 2011 and to drill 17 wells (5.1 net to us).

From 2010 through 2011 we spent approximately $147.7 million to acquire 35,335 acres (27,856 net to us) in South Texas which we believe to be prospective for oil in the Eagle Ford shale formation. We spent approximately $200.7 million to drill 20 wells (19.2 net to us) in 2011 on our Eagle Ford shale properties. Our Eagle Ford shale drilling program added 10.6 million barrels of oil equivalent to our proved reserves in 2011. We plan to continue to develop our Eagle Ford shale properties in 2012 and have budgeted $192.9 million to drill 24 wells (21.7 net to us) during 2012 and to complete four wells that were drilled in 2011.

During 2011 we spent approximately $345.5 million to acquire 70,036 acres (43,591 net to us) in Reeves County in West Texas which we believe to be prospective for oil in the Bone Spring and Wolfcamp shale in the Delaware Basin. This acquisition included 35 producing wells and four wells that were waiting to be completed. The proved reserves acquired with the acquisition were estimated at 25.2 million barrels of oil equivalent. We also spent $8.0 million to acquire 19,847 acres (11,875 net to us) in Gaines County that is prospective for the Wolfcamp shale. We plan to develop these properties during 2012 and have budgeted $158.3 million to drill 43 wells (33.8 net to us) during 2012.

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. During 2011, outside of our Haynesville shale and Eagle Ford shale drilling programs, we spent $2.8 million to drill five wells

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(0.5 net to us). We also spent $7.3 million for development leasehold, recompletions and workover activity in 2011.

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 expenditures according to market conditions. We have budgeted to spend approximately $458.0 million on our development and exploration projects in 2012. We intend to primarily use operating cash flow, proceeds from the sale of non-core assets and borrowings under our bank credit facility to fund our development and exploration expenditures in 2012. We may also make additional property acquisitions in 2012 that would require additional sources of funding. Such sources may include borrowings under our bank credit facility or sales of our equity or debt securities.

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. During 2011 we completed two acquisitions of producing oil and gas properties. We acquired 25.2 million barrels of oil equivalent in the Delaware Basin in West Texas for $201.8 million on December 29, 2011. We also acquired 13 Bcfe of proved reserves in North Louisiana for $16.9 million on December 30, 2011. 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.

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Primary Operating Areas

The following table summarizes the estimated proved oil and natural gas reserves for our twenty largest field areas as of December 31, 2011:

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East Texas/North Louisiana Region

Approximately 70% or 917.9 Bcfe of our proved reserves are located in East Texas and North Louisiana where we own interests in 1,010 producing wells (602.9 net to us) in 29 field areas. We operate 679 of these wells. The largest of our fields in this region are the Logansport, Toledo Bend, Beckville, Waskom, Blocker, Mansfield, Hico-Knowles, Darco, Douglass, Longwood and Drew fields. Production from this region averaged 211 MMcf of natural gas per day and 320 barrels of oil per day during 2011 or 212.6 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 2011, we spent $242.3 million drilling 64 wells (28.3 net to us) and $121.2 million completing wells that were drilled in 2010. We also spent $38.4 million on leasehold costs and $4.1 million on workovers and recompletions in this region. 62 (28.0 net to us) of the 64 wells we drilled were horizontal wells that targeted the Haynesville or Bossier shale. As of December 31, 2011 we had 14 (9.8 net to us) Haynesville and Bossier shale wells that had been drilled but which were not yet completed. We plan to spend approximately $106.8 million in 2012 in this region to complete these wells and to drill 17 (5.1 net to us) Haynesville or Bossier shale wells.

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 552.5 Bcfe in the Logansport field represent approximately 42% of our proved reserves. We own interests in 242 wells (152.4 net to us) and operate 168 of these wells in this field. During December 2011 net daily production attributable to our interest from this field averaged 120 MMcf of natural gas and 30 barrels of oil. In 2011 we drilled 22 (15.3 net to us) Haynesville or Bossier shale horizontal wells at Logansport, and we completed 21 wells (15.4 net to us) that were drilled in 2010. In 2012 we plan to drill three (0.6 net to us) horizontal Haynesville or Bossier shale wells at Logansport.

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 158.8 Bcfe in the Toledo Bend field represent approximately 12% of our reserves. We own interests in 55 producing wells (31.7 net to us) and operate 34 of these wells in this field. During 2011 we drilled 32 (10.8 net to us) Haynesville or Bossier shale horizontal wells at Toledo Bend and we completed six wells (4.6 net to us) that were drilled in 2010. During December 2011, net daily production attributable to our interest from this field averaged 45 MMcf of natural gas. In 2012, we plan to drill eleven (3.9 net to us) horizontal Haynesville or Bossier shale wells in this field.

Beckville

The Beckville field, located in Panola and Rusk Counties, Texas, has estimated proved reserves of 50.7 Bcfe which represents approximately 4% of our proved reserves. We operate 193 wells in this field and own interests in 83 additional wells for a total of 276 wells (161.2 net to us). During December 2011, production attributable to our interest from this field averaged 10 MMcf of natural gas per day and 60 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 3% (44.8 Bcfe) of our proved reserves as of December 31, 2011. We own interests in 69 wells in this field (44.5 net to us) and operate 52 wells in this field. During December 2011, net daily production attributable to our interest averaged 7 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. We drilled one Haynesville shale well in the Waskom field in 2011.

Blocker

Our proved reserves of 27.8 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 2011, net daily production attributable to our interest from this field averaged 5 MMcf of natural gas and 30 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. During 2011 we drilled six (0.5 net to us) Haynesville shale horizontal wells and completed six wells (2.2 net to us) that were drilled but not completed in 2010 in this field. Our proved reserves in this field of 25.1 Bcfe represent approximately 2% of our reserves. During December 2011, net daily production attributable to our interest for this field averaged 9 MMcf of natural gas. In 2012, we plan to drill three (0.6 net to us) horizontal Haynesville or Bossier shale wells.

Hico-Knowles

We have 18.5 Bcfe of proved reserves in the Hico-Knowles field area located in Lincoln County, Louisiana which represent approximately 1% of our reserves. We own interests in 68 wells (24.2 net to us) and operate 22 of these wells. This field produces primarily from the Hosston/Cotton Valley formations between 7,200 and 11,000 feet. During December 2011, net daily production attributable to our interest from this field averaged 4 MMcf of natural gas and 71 barrels of oil.

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 7.9 Bcfe in the Darco field represent approximately 1% of our reserves. We own interests in 24 wells (18.8 net to us) and operate all of these wells. During December 2011, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas and 4 barrels of oil.

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

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from 9,200 to 10,300 feet. Our proved reserves of 7.5 Bcfe in the Douglass field represent approximately 1% of our reserves. We own interests in 40 wells (25.8 net to us) and operate 33 of these wells. During December 2011, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas.

Longwood

The Longwood field, located in Harrison County, Texas primarily produces from stacked sandstone reservoirs of the Travis Peak and Cotton Valley formations at depths ranging from 6,000 to 10,000 feet. We own interests in 22 wells (17.9 net to us) in this field and operate 19 wells in this field. Our proved reserves of 6.7 Bcfe in the Longwood field represent approximately 1% of our reserves. During December 2011, net daily production attributable to our interest from this field averaged 2 MMcf of natural gas and 3 barrels of oil.

Drew

The Drew field located in Ouachita Parish, Louisiana has estimated proved reserves of 3.5 Bcfe which represents less than 1% of our total company proved reserves. Production is from the Cotton Valley formation between 9,000 feet and 9,600 feet. We own interest in eight wells (5.3 net to us) and operate six of these wells. During December 2011, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas and 6 barrels of oil per day.

South Texas Region

Approximately 17%, or 221.4 Bcfe, of our proved reserves are located in South Texas, where we own interests in 240 producing wells (137.6 net to us). We own interests in 15 field areas in the region, the largest of which are the Eagle Ford, Fandango, Double A Wells, Rosita, Javelina, Las Hermanitas and Segno fields. Net daily production rates from this region averaged 31 MMcf of natural gas and 1,911 barrels of oil during 2011 or 42 MMcfe per day. We spent $66.4 million in this region in 2011 to acquire acreage which is prospective for development of the Eagle Ford shale. We also spent $202.8 million to drill 20 (19.2 net to us) Eagle Ford shale wells and for other development activity. In 2012 we plan to spend approximately $192.9 million to drill 24 (21.7 net to us) Eagle Ford shale wells and to complete four (3.2 net to us) Eagle Ford shale wells that were drilled in 2011.

Eagle Ford

We have 35,335 acres (27,856 net to us) distributed across 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 2011 we had 19 wells (19.0 net to us) that were producing a total of 4,601 barrels of oil per day and 4 MMcf per day of natural gas net to our interest. Our Eagle Ford proved reserves are estimated to be 72.4 Bcfe (88% oil) and represent 6% of our reserves. We plan to spend approximately $192.9 million in 2012 to drill 24 (21.7 net to us) Eagle Ford shale wells and to complete four (3.2 net to us) Eagle Ford shale wells that were drilled in 2011.

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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 50 Bcfe in this field represent approximately 4% of our total reserves. Production from this field averaged 10 MMcf of natural gas per day during December 2011.

Double A Wells

Our properties in the Double A Wells field have proved reserves of 40 Bcfe, which represent 3% of our reserves. We own interests in and operate 54 producing wells (25.5 net to us) in this field in Polk County, Texas. Net daily production from the Double A Wells area averaged 5 MMcf of natural gas and 156 barrels of oil during December 2011. These wells produce from the Woodbine formation at an average depth of 14,300 feet.

Rosita

We own interests in 31 wells (16.8 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 25.3 Bcfe in this field represent approximately 2% of our total reserves. Production from this field averaged 4 MMcf of natural gas per day during December 2011.

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 12.3 Bcfe, which represents 1% of our total proved reserves. During December 2011, production attributable to our interest from this field averaged 3 MMcf of natural gas per day and 32 barrels of oil per day.

Las Hermanitas

We own interests in and operate 13 (10.6 net to us) natural gas wells 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 8.5 Bcfe in this field represent approximately 1% of our proved reserves. During December 2011, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas.

Segno

The Segno Field located in Polk County, Texas has estimated proved reserves of 3.2 Bcfe which represents less than 1% of our total company proved reserves. Production is from shallow Yegua sands from 5,000 feet to 5,600 feet and deep Wilcox sands between 11,300 feet to 13,350 feet. We own interests in 16 wells (11.3 net to us) and do not operate any of the wells. During December 2011, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas and 125 barrels of oil per day.

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West Texas Region

Wolfbone

On December 29, 2011, we acquired interests in 70,036 acres (43,591 net to us) 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. Included in this acquisition were 35 wells (22.4 net to us) that were producing and four wells (2.5 net to us) that were waiting on completion. Our proved reserves of 151.2 Bcfe in the West Texas region are 75% oil and represent 12% of our proved reserves. For 2012 we have budgeted to spend $158.3 million to drill 43 wells (33.8 net to us) in this region and to complete the wells drilled in 2011. During December 2011, production from the wells acquired averaged 1,000 barrels of oil and 2 MMcf of natural gas per day.

Other Regions

Approximately 2%, or 20.8 Bcfe, of our proved reserves are in other regions, primarily in New Mexico, Kentucky and the Mid-Continent region. We own interests in 426 producing wells (162.7 net to us) in 15 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 2011 totaled 7 MMcf of natural gas and 65 barrels of oil or 7.4 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 4.2 Bcfe in the San Juan field represent less than 1% of our reserves. We own interests in 96 wells (14.5 net to us) in this field. During December 2011, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas and 3 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 $345.5 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.

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, Blocker and Hico-Knowles fields. The net proved reserves acquired in this acquisition were estimated at 0.8 MMBbls of oil and 104.7 Bcf of natural gas.

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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, 2011:

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

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.

In connection with estimating proved undeveloped reserves for our December 31, 2011 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.

There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude 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

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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 crude oil and natural gas that are ultimately recovered.

The average prices that we realized from sales of oil and natural gas, including 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:

The oil and natural gas prices used for reserves estimation were as follows:

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.

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 addition, undeveloped reserves may be estimated through the use of reliable technology in addition to flow tests and production history. As of December 31, 2011, our proved reserves included 23.7 MMBbls of crude oil and 568 Bcf of natural gas, for a total of 710 Bcfe of undeveloped reserves. Approximately 60% of our proved undeveloped reserves at December 31, 2011 were related to our Haynesville or Bossier shale properties primarily in North Louisiana, 19% was related to our Delaware Basin properties in West Texas and 6% was related to our Eagle Ford shale properties in South Texas. 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. Our 2011 proved undeveloped reserves increased 184 Bcfe from 526 Bcfe at the end of 2010. This increase was primarily due to the 148 Bcfe of proved undeveloped reserves that were acquired in connection with two acquisitions that were completed in December 2011. We also added 98 Bcfe of undeveloped reserves and converted 40 Bcfe of 2010’s undeveloped reserves to proved developed reserves as a result of our 2011 drilling activity. Proved undeveloped reserves were reduced by revisions of 22 Bcfe related to revisions of previous estimates. We spent $56.3 million in 2011 to convert 2010’s undeveloped reserves and $149.1 million to convert 2010’s proved developed nonproducing reserves to proved developed producing reserves. All undeveloped drilling locations which comprise our undeveloped reserves at December 31, 2011 are scheduled to be drilled within five years of the year that such reserves were first included in our reported reserves.

Our estimates of crude oil and natural gas reserves include 342 Bcfe related to undrilled wells that have positive undiscounted future cash flows but which, based upon crude 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

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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, 2011 based upon the crude 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 crude 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.

We had proved reserve additions of 140 Bcfe in 2011 relating to discoveries resulting from our Haynesville and Bossier shale drilling program. These reserve additions related to 96 Bcfe assigned to 62 (28.0 net to us) Haynesville and Bossier shale wells that we drilled and 44 Bcfe assigned to 58 proved undeveloped locations (20.7 net to us) offsetting these wells. During 2011 we continued to drill wells to evaluate our acreage which is prospective for the Eagle Ford shale. Based on the drilling results from our first successful wells, we added 64 Bcfe (88% crude oil) to our proved reserves in 2011. We also had an additional 151 Bcfe (75% crude oil) of reserve additions from our acquisition of properties in West Texas and 13 Bcfe from our acquisition of properties which are prospective for Haynesville or Bossier shale development.

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 Asset Management Group, comprised of qualified petroleum engineers, works with our accounting, land, marketing and other groups in order to accumulate the information required for the reserves estimation process. 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.

Our Asset Manager, who reports to our Vice President of Operations, is the primary person in charge of overseeing our reserve estimates. He has a degree in Petroleum Engineering and has over seventeen years of experience in various technical roles within the oil and gas industry. Working with our Asset Manager is a staff of three petroleum engineering professionals. The average experience of our petroleum engineers is 18 years. Our Vice President of Operations also reviews and approves our final reserve estimates. Our Vice President of Operations has a degree in Petroleum Engineering and has over 27 years of experience holding various technical and managerial roles in the oil and gas industry.

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We did not provide estimates of total proved oil and natural gas reserves during the years ended December 31, 2009, 2010 or 2011 to any federal authority or agency, other than the SEC.

Drilling Activity Summary

During the three-year period ended December 31, 2011, we drilled development and exploratory wells as set forth in the table below:

In 2012 to the date of this report, we have drilled 15 wells (9.7 net to us) and we have six wells (3.6 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, 2011:

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We operate 974 of the 1,711 producing wells presented in the above table. As of December 31, 2011, we owned interests in 16 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.

Acreage

The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2011, 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.

Our undeveloped acreage expires as follows:

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 2012 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

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with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Our oil production is 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 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 85% of our 2011 natural gas sales were priced utilizing first of the month index prices and approximately 15% were priced utilizing daily spot prices. BP Energy Company and its subsidiaries and Shell Oil Company and its subsidiaries accounted for 49% and 14%, respectively, of our total 2011 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.

With the significant increase in our natural gas production in North Louisiana due to our Haynesville shale drilling program, we have entered into longer term marketing arrangements to ensure that we have adequate transportation to get our natural gas production 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 dedicated a substantial portion of our production in our Logansport and Toledo Bend fields under such agreements for terms that expire from 2016 to 2020. We have a commitment to transport a minimum of 1.1 Bcf over 3.2 years under one of these agreements.

We have also 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,

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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.

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. Additionally, some of our federal leases are subject to the Indian Mineral Development Act of 1982, and are therefore subject to supplemental regulations and orders of the Department of Interior’s Bureau of Indian Affairs. While we cannot predict how various federal agencies may change their interpretations of existing regulations and orders or how regulations and orders issued in the future will impact our operations located on these federal leases, we do not believe we will be affected differently than other similarly situated oil and natural gas producers.

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

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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, 2011. The mandatory five year review in 2011 revised the methodology for this index to be based on PPI-FG plus 2.65 percent for the period July 1, 2011 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

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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.

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. 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

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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.

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 2011, 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 2011, with the first annual reports of those emissions due on March 31, 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

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global warming potential, so 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 are implementing procedures to collect the required information.

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, Livingston, and Zapata, Texas; Logansport, Louisiana and Guston, Kentucky.

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Employees

As of December 31, 2011, we had 124 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.

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, 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.

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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.

Mark A. Williams was appointed our Vice President of Operations in February 2011. From 2007 to 2010, 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.

Stephen E. Neukom has been our Vice President of Marketing since 1997 and has served as our manager of crude 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.

Richard D. Singer has been our Vice President of Financial Reporting since 2005. Mr. Singer has over 35 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.

Outside Directors

David K. Lockett has served as a director since 2001.    Mr. Lockett is a Vice President with Dell Inc. and has held executive management positions in several divisions within Dell since 1991. Mr. Lockett has been employed by Dell Inc. for the past 20 years and has been in the technology industry for the past 35 years. Mr. Lockett was a director of Bois d’Arc Energy, Inc. from 2005 until its merger with Stone Energy Corporation in 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. 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.

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David W. Sledge has served as a director since 1996.    Mr. Sledge is a Vice President 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 Trustees of the Presbyterian Hospital of Dallas Foundation.

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.

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. 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:

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If the decline in the price of natural gas that first started in 2008 continues through 2012, the lower prices will adversely affect:

We have entered into certain oil price hedging arrangements on certain of our anticipated sales. 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 2012 and beyond, and the capital markets have experienced significant volatility. The recession has had an adverse impact on demand and pricing for crude 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.

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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 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 crude 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 2012 utilize hydraulic fracturing in their completion. We estimate we will incur approximately $185.0 million for hydraulic fracturing services in connection with our 2012 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 2011 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

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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 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 $1.2 billion in debt as of December 31, 2011, and our ratio of total debt to total capitalization was approximately 54%.

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

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:

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Our failure to comply with any of these covenants could cause a default under our bank credit facility and the respective indentures governing our 8 ³/8% senior notes due 2017 and 7 ³/4% senior notes due 2019. 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.

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: