(Mark  One)

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

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yesþ    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. þü

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

The aggregate market value of the common stock held by non-affiliates of the registrant, based on the closing price of common stock on the New York Stock Exchange on June 30, 20122013 (the last business day of the registrant’s most recently completed second fiscal quarter), was $734.6$705.7 million.

As of February 26, 2014, there were 47,837,224 shares of common stock of the registrant outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Definitive Proxy Statement for the 20122014 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, 20122013

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.

“BOE”means one barrel of oil equivalent.

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

“Completion”means the installationinstallation 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 withinwithin 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 productionproduction 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 naturalnatural gas equivalent.

“MMBbls”means one million barrels of oil.

“MMBOE” means one million barrels of oil equivalent.

“MMBtu” means one million British thermal units.

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

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

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

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

“Net”when used with respect to acres or wells, refers to grossgross 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 calculatedcalculated 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) expectedexpected 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 includes 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.arrangements.

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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 beare limited to those drilling unitslocations offsetting productive unitswells that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed onlydrilled or 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 leaselease 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 theythey 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.In May 2013, we divested all of our oil and gas properties in West Texas and, accordingly, the discussion which follows pertains solely to our continuing oil and gas operations.

Our oil and gas operations are concentrated in East Texas/North Louisiana, South Texas and West Texas.Louisiana. Our oil and natural gas properties are estimated to have proved reserves of 711.9585 Bcfe with an estimated PV 10 Value of $1.0$1.1 billion as of December 31, 20122013 and a standardized measure of discounted future net cash flows of $0.8 billion. Our consolidated proved oil and natural gas reserve base is 67%77% natural gas and 33% oil. Our proved reserves23% oil and are 62%73% developed on a Bcfe basis as of December 31, 2012.2013.

Our proved reserves at December 31, 20122013 and our 20122013 average daily production are summarized below:

Strengths

High Quality Properties.     Our operations are currently focused in three primarytwo operating areas: East Texas/North Louisiana South Texas and WestSouth Texas. Our properties have an average reserve life of approximately 7.48.4 years and have extensive development and exploration potential. In response to the continuing low natural gas price environment in recent years, we have focused our drilling activity primarily on oil projects.projects and limited our natural gas drilling to wells required to hold acreage. Our two primary properties that provide opportunitiesEagleville field includes 31,755 acres (25,316 net to increase ourus) located in the oil production and reserves are our South Texaswindow of the Eagle Ford shale propertiesin South Texas. In 2013 94% of our drilling and completion expenditures were related to our WolfboneEagleville field development. During 2013, we acquired acreage in West Texas. We have 34,727two additional areas that are prospective for oil, including 33,624 acres (27,689(21,034 net to us) in the Eagle Fordoil window of the Eagleford shale in or near Burleson County, Texas, and we have 88,66653,470 acres (54,355(51,017 net to us) in West TexasMississippi and Louisiana that are prospective for development in the Bone Spring and Wolfcamp shales.Tuscaloosa Marine shale. Our properties in the East Texas/North Louisiana region, including 93,620which are primarily prospective for natural gas, include 84,875 acres (80,046(72,232 net to us) in the Haynesville or Bossier shales, are primarily prospective for natural gas.shale formations.

Successful Exploration and Development Program.     In 20122013 we spent $524.9$481.1 million net of reimbursed costs from our joint venture partner, on exploration and development activities. We spent $338.0 million on drilling and completing wells in 2013. We drilled 8577 wells (54.2(53.6 net to us) in 2012 at a cost of $415.1 million and we spent $70.9 million to complete 20completed 67 wells (13.6(44.1 net to us) that were drilled in 2011.. We also spent $35.1$137.1 million in 20122013 to acquire additional leasehold, $0.1$0.4 million to acquire seismic data and $3.7$5.6 million for recompletions, workovers, abandonment, and production facilities. 80% ofOf our 20122013 capital expenditures, 95% were directed towards oil projects. Our drilling activities in 20122013 added 22.513.2 MMBOE to our proved reserves and increased our oil production in 2013 by 175%29% from 2011.2012's oil production.

Efficient Operator.     We operated 90%95% of our proved oil and natural gas reserve base as of December 31, 2012.2013. As operator we are better able to control operating costs, the timing and plans for

future development, the

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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 recent years we have focused primarily on acquiring undrilled acreage rather than producing properties. 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 of producing oil and gas properties 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   Each year, we conduct exploration activities to grow our reserve base and to replace our production each year. During 2012production. In recent years we refocused our effortshave been focused on prospects with potential for oil development, and we have limited our drilling on our natural gas properties due to the decline inweak natural gas prices.

In 2013 our Eagleville field in South Texas was the primary focus of our drilling activity. From 2010 through 20122013, we spent approximately $155.2$169.5 million to acquire 34,727 acres (27,689 net to us)leasing acreage in McMullen, Atascosa, Frio, La Salle, Karnes and Wilson Counties in South Texas, which we believe to be prospective for oil in the Eagle Ford shale formation. In 2012 we spent approximately $201.7 million to drill 30 wells (20.5 net to us) on our Eagle Ford shale properties. In 2012 we entered into a joint venture arrangement to allow us to accelerate the development of our acreage.this field. Our joint venture partner participates for a one-third interest in the wells that we drill in exchange for paying $25,000 per net acre that is earned by their participation. Through December 31, 2013, we have drilled 128 wells (94.3 net to us) in our Eagleville field including 75 wells (51.6 net to us) drilled in 2013. Our joint venture partner participated in 96 of these wells and contributed $61.3 million through December 31, 2013 for acreage and an additional $5.0 million to reimburse us for a portion of common production facilities. In 2012, our Eagle Ford shale drilling program2013, we added 13.26.1 MMBOE to our proved reserves. In 2013 wereserves from our drilling activity in Eagleville. We have budgeted to spend $219.0$344.0 million in 2014, net of reimbursements from our joint venture partner, to drill 4259 wells (27.3(40.2 net to us) on our Eagle Ford shale properties and to complete six18 wells (3.8(13.3 net to us) that were drilled in 2012.2013.

In May 2013 we completed the divestiture of our West Texas properties that were acquired in 2011.  We havereceived proceeds of $823.1 million from the sale and recognized a gain of $230.0 million ($148.6 million after income taxes).  We divested of the properties due to the substantial drilling required to maintain the leases, the opportunity to earn a substantial profit from our investment and the low returns we were realizing from our 2012 drilling activity.  The divestiture allowed us to repay $722.0 million of our long-term debt and to accelerate the development of our Eagleville field.

We spent approximately $340.0$67.4 million in 2013 to acquire 68,764lease 33,624 acres (41,071(21,034 net to us)us) in Reevesor near Burleson County, in West  Texas which we believe to beare prospective for oil in the Bone SpringEagle Ford shale formation, and Wolfcamp shales in the Delaware Basin. During 2012 we spent $183.4$53.3 million and drilled 48 wells (30.5to acquire 53,470 acres (51,017 net to us) in West Texas. Our drilling program added 6.9 MMBOE to our reservesLouisiana and Mississippi, which are prospective for oil in 2012. In 2013 wethe Tuscaloosa Marine shale.  We have budgeted $168.9$77.0 million to drill 33in 2014 for drilling 12 wells (27.2(7.4 net to us), including eight horizontal Wolfcamp shale wells (7.3 net to us). on the new acreage.

We have a significant acreage position of 93,62084,875 acres (80,046(72,232 net to us) in East Texas and North Louisiana with Haynesville or Bossier shale natural gas potential, but in 20122013 we have deferredelected to defer most of our drilling operations due to the lowuntil natural gas price environment. In 2012, weprices improve. We drilled seventwo Haynesville and Bossier shale horizontal wells (3.2(2.0 net to us) in 2013, which added 1437 Bcfe to our proved reserves in 2012. With the low natural gas price outlook in 2013, we continue to defer our natural gas focused drilling. We have budgeted to spend $32.1 million in 2013 to drill ten Haynesville and Bossier shale horizontal wells (3.6 net to us).reserves.

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, improvedenhanced logging tools, and formation stimulation techniques.

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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 $420.0$450.0 million in 20132014 on our development and exploration projects and $25.0$28.0 million for lease acquisition activity.

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

Primary Operating Areas

The following table summarizes the estimated proved oil and natural gas reserves for our fifteen largest field areas as of December 31, 2012:2013:

________________

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East Texas/North Louisiana Region

Approximately 48%59% or 341.9343.8 Bcfe of our proved reserves are located in East Texas and North Louisiana where we own interests in 958956 producing wells (585.8(584.8 net to us) in 28 field areas. We operate 664662 of these wells. The largest of our fields in this region are the Logansport, Toledo Bend, Beckville, Waskom, Blocker, Mansfield, DarcoDouglass and DouglassDarco fields. Production from this region averaged 194128 MMcf of natural gas per day and 220175 barrels of oil per day during 20122013 or 196130 MMcfe per day. Most of the reserves in this area produce from the upper Jurassic aged Haynesville or Bossier shale or Cotton Valley formations and the Cretaceous aged Travis Peak/Hosston formation. In 2012,2013, we spent $101.1$16.7 million drilling seventwo wells (3.2(2.0 net to us) and completing 16 wells (10.4 net to us) that were drilled in 2011. We also spent $8.2 million on leasehold costs and $1.7$2.3 million on workovers and recompletions in this region. All seven of theThe two wells we drilled in 20122013 were Bossier shale horizontal wells that targeted the Haynesville or Bossier shales.wells. We planhave not budgeted to spend approximately $32.1 million in 2013drill any wells in this region to drill ten (3.6 net to us) horizontal wells targeting the Haynesville or Bossier shales. These wells are required to retain our interest in certain undeveloped leases.2014.

Logansport

Logansport

The Logansport field located in DeSoto Parish, Louisiana primarily produces from the Haynesville and Bossier shale formations at a depth of 11,100 to 11,500 feet and from multiple sands in the Cotton Valley and Hosston formations at an average depth of 8,000 feet. Our proved reserves of 212.3232.8 Bcfe in the Logansport field represent approximately 30%40% of our proved reserves. We own interests in 254252 wells (163.2(161.9 net to us) and operate 180178 of these wells in this field. During December 2012 net daily production attributable to our interest from this field averaged 94 MMcf of natural gas and 20 barrels of oil. In 2012 we completed ten Haynesville or Bossier shale horizontal wells (8.2 net to us) in Logansport that were drilled in 2011. In 2013 we plan to drill three horizontal Haynesville or Bossier shale wells (0.6 net to us) in our Logansport field.

Toledo Bend

Toledo Bend

The Toledo Bend field in DesotoDeSoto 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 4531.1 Bcfe in the Toledo Bend field represent approximately 6%5% of our reserves. We own interests in 7276 producing wells (37.3(39.3 net to us) and operate 3941 of these wells in this field. During 20122013 we drilled four Haynesville or Bossier shaletwo horizontal wells (1.3(2.0 net to us) at Toledo Bend and we completed sixtwo wells (2.1(0.1 net to us) that were drilled in 2011. During December 2012, net daily production attributable to our interest from this field averaged 35 MMcf of natural gas. In 2013, we plan to drill five horizontal Haynesville or Bossier shale wells (2.6 net to us) in this field.2012.

Beckville

Beckville

The Beckville field, located in Panola and Rusk Counties, Texas, has estimated proved reserves of 31.930.6 Bcfe which represents approximately 5% of our proved reserves. We operate 192191 wells in this field and own interests in 8178 additional wells for a total of 273269 wells (160.4(159.3 net to us). During December 2012, production attributable to our interest from this field averaged 8 MMcf of natural gas per day and 40 barrels of oil per day. The Beckville field produces primarily from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet. The field is also prospective for future Haynesville shale development.

Waskom

Waskom

The Waskom field, located in Harrison and Panola Counties in Texas, represents approximately 2% (14.8(12.7 Bcfe) of our proved reserves as of December 31, 2012.2013. We own interests in 63 wells in this field (40.5(39.8 net to us) and operate 4847 wells in this field. During December 2012, net daily production attributable to our interest averaged 5 MMcf of natural gas and 20 barrels of oil from this field. The Waskom field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet and from the Haynesville shale formation at depths of 10,800 to 10,900 feet.

Blocker

Blocker

Our proved reserves of 11.212.1 Bcfe in the Blocker field located in Harrison County, Texas represent approximately 2% of our proved reserves. We own interests in 77 wells (71.0 net to us) and operate 71 of these wells. During December 2012, net daily production attributable to our interest from this field averaged 4 MMcf of natural gas and 22 barrels of oil. Most of this production is from the Cotton Valley formation between 8,600 and 10,150 feet and the Haynesville shale formation between 11,100 and 11,450 feet.

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Mansfield

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 four4 of these wells. Our proved reserves in this field of 8.67.1 Bcfe represent approximately 1% of our total reserves. During December 2012, net daily production attributable to our interest for this field averaged 4 MMcf of natural gas. In 2013, we plan to drill two (0.4 net to us) horizontal Haynesville shale wells in this field.

Douglass

Darco

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

Douglass

The Douglass field is located in Nacogdoches County, Texas and is productive from stratigraphically trapped reservoirs in the Pettet Lime and Travis Peak formations. These reservoirs are found at depths from 9,200 to 10,300 feet. Our proved reserves of 3.03.6 Bcfe in the Douglass field represent less than 1% of our reserves. We own interests in 40 wells (25.8 net to us) and operate 33 of these wells. During December 2012,

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 2.8 Bcfe in the Darco field represent less than 1% of our reserves.  We own interests in 23 wells (18 net daily production attributable to our interest from this field averaged 1 MMcfus) and operate all of natural gas.these wells.  

South Texas Region

Approximately 28%39%, or 32.837.9 MMBOE (196.5 Bcfe,)(227.6 Bcfe), of our proved reserves are located in South Texas, where we own interests in 191240 producing wells (116.6(151.7 net to us). We own interests in 1613 field areas in the region, the largest of which are the Eagleville, Fandango, Rosita, Javelina, and Las Hermanitas and Lopeno fields. Net daily production rates from this region averaged 4,5876,110 barrels of oil and 2420 MMcf

of natural gas during 20122013 or 8,5219,388 BOE per day. We spent $202.9$325.0 million in 2012, net of cost recoveries from our joint venture partner,2013 to drill 30 (20.575 oil wells (51.6 net to us) targeting the Eagle Ford shale wells and for other development activity. We also spent $7.7$77.2 million in this region in 20122013 to acquire acreage. In 2013 weacreage, including $67.4 million for 33,624 acres (21,034 net to us) in or near Burleson County, Texas which are prospective in the Eagle Ford shale formation.   We plan to spend approximately $219.0$264.0 million in 2014 to drill 59 horizontal wells (40.2 net to us) in our Eagleville field, $50.0 million to drill 42 horizontalten wells (27.3(5.6 net to us) and to complete sixin our newly acquired Eagle Ford shale acreage, $80.0 million to complete 18 Eagleville wells (3.8(13.3 net to us) that were drilled in 2012.2013 and $25.0 million on facilities, recompletions and other capital projects.

Eagleville

Eagleville

We have 34,72731,755 acres (27,689(25,316 net to us) in McMullen, Atascosa, Frio, La Salle, Atascosa,Karnes and Wilson and Karnes Counties which are prospective forcomprise our Eagleville field. The 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. DuringAt December 201231, 2013 we had 49101 wells (40.5(74.6 net to us) that were producing a total of 4,023 barrels of oil per day and 2.4 MMcf per day of natural gas net to our interest or 4,418 BOE per day.in the Eagleville field. Our proved reserves in this field are estimated to be 20.624.4 MMBOE (123.7(146.6 Bcfe) (89%(87% oil) and represent 17%25% of our total proved reserves. All of our planned South Texas drilling activityWe plan to spend approximately $264.0 million in 2014 to drill 59 horizontal wells (40.2 net to us) and $80.0 million to complete wells that were drilled in 2013 will be in the Eagleville field.

Fandango

Fandango

We own interests in 2019 wells (20.0(19.0 net to us) in the Fandango field located in Zapata County, Texas. We operate all of these wells which produce from the Wilcox formation at depths from approximately 13,000 to 18,000 feet. Our proved reserves of 37.345.4 Bcfe in this field represent approximately 5%8% of our total proved reserves. Production from this field averaged 9 MMcf of natural gas per day during December 2012.

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Rosita

Rosita

We own interests in 3029 wells (16.2(15.7 net to us) in the Rosita field, located in Duval County, Texas. We operate four28 of these wells which produce from the Wilcox formation at depths from approximately 9,300 to 17,000 feet. Our proved reserves of 16.3 Bcfe in this field represent approximately 2%3% of our total proved reserves. Production from this field averaged 3 MMcf of natural gas per day during December 2012.

Javelina

Javelina

We own interests in and operate 18 wells (18.0 net to us) in the Javelina field in Hidalgo County in South Texas. These wells produce primarily from the Vicksburg formation at a depth of approximately 10,900 to 12,500 feet. Proved reserves attributable to our interests in the Javelina field are 8.07.8 Bcfe, which represents approximately 1% of our total proved reserves. During December 2012, production attributable to our interest from this field averaged 3 MMcf of natural gas per day and 21 barrels of oil per day.

Las Hermanitas

Las Hermanitas

We own interests in and operate 11 natural gas wells (9.0(11.0 net to us) in the Las Hermanitas field, located in Duval County, Texas. These wells produce from the Wilcox formation at depths from approximately 11,400 to 11,800 feet. Our proved reserves of 4.55.7 Bcfe in this field represent approximately 1% of our total proved reserves. During December 2012, net daily production attributable to

Lopeno

The Lopeno Field located in Zapata County, Texas has estimated proved reserves of 2.5 Bcfe which represents less than 1% of our interesttotal company proved reserves.  Production is from this field averaged 2 MMcf of natural gas.

shallow Queen City sands between 2,200 feet and 2,600 feet and deeper Wilcox sands bWest Texas Region

Wolfbone

etween 6,400 feet and 12,500 feet.  We own interests in 68,764 acres (41,07117 wells (2.7 net to us) in Reeves County in the Delaware Basin in West Texas that are prospective for the Bone Spring formation from depthsand operate one of 10,000 to 10,300 feet and the Wolfcamp shale formation from depths of 10,300 to 11,500 feet, most of which was acquired by us in 2011. Our proved reserves of 26.8 MMBOE (161.1 Bcfe) in the Wolfbone field are 76% oil and represent 23% of our total proved reserves. Net daily production rates from this region averaged 1,410 barrels of oil and 2 MMcf of natural gas during 2012 or 1,744 BOE per day. During 2012 we spent $183.9 million to drill 48 (30.5 net to us) oil wells and for other development activity. We also spent $19.2 million in this region in 2012 to acquire acreage. In 2013 we have budgeted to spend $168.9 million to drill 33 wells (27.2 net to us) in this region and to complete three wells (1.0 net to us) drilled in 2012.these wells.  

Other Regions

Other Regions

Approximately 2%2%, or 12.413.1 Bcfe, of our proved reserves are in other regions, primarily in New Mexico and the Mid-Continent region. We own interests in 421339 producing wells (161.0(85.3 net to us) in 2015 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 20122013 totaled 65 MMcf of natural gas and 8754 barrels of oil or 65 MMcfe per day.

During 2013, we spent $53.3 million to acquire 53,470 acres (51,017 net to us) in Louisiana and Mississippi which are prospective for oil in the Tuscaloosa Marine shale.  We have budgeted $27.0 million in 2014 to drill two wells (1.8 net to us) on this acreage.

San Juan

Our San Juan Basin properties are located in the west-central portion of the basin in San Juan County, New Mexico. These wells produce from multiple sands of the Cretaceous Dakota formation and the Fruitland Coal seams. The Dakota is generally found at about 6,000 feet with the shallower Fruitland seams encountered at 2,500 to 3,000 feet. Our proved reserves of 3.42.8 Bcfe in the San Juan field represent less than 1% of our reserves. We own interests in 9392 wells (14.1(14.0 net to us) in this field. During December 2012, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas and 2 barrels of oil.

Major Property Acquisitions

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

Delaware Basin Acquisition. In December 2011, we acquired certain oil and gas properties from Eagle Oil & Gas Co. and other third parties for $348.7 million. The properties acquired had estimated

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proved reserves of approximately 151.2 Bcfe and included approximately 65,000 exploratory acres (39,100 net to us). We divested of these properties in May 2013.

Shell Wilcox Acquisition.In December 2007, wewe 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.

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”“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 approximatelyapproximately $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 undevelopedundeveloped 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

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reserves acquired in this acquisition were estimated at 5.9 MMBbls of oil and 100.4 Bcf of natural gas. We divested of these properties in 2012.

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

Oil and Natural Gas Reserves

The following table sets forth our estimated proved oil and natural gas reserves and the PV 10 Value as of December 31, 2012:2013:

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 economiceconomic producibility include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available production data, seismic data and well test data.

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

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revision of such estimate. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

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

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

Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered, and they are scheduled to be drilled within five years of their initial inclusion as proved reserves, unless specific circumstances justify a longer time. In connection with estimating proved undeveloped reserves for our December 31, 20122013 reserve report, reserves on undrilled acreage were limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled.drilled where we can verify the continuity of the reservoir. Using empirical evidence, we utilize control points and sample sizes to show continuity in the reservoir.

The following table presents We reflect changes to undeveloped reserves that occur in the same field as revisions to the extent that proved undeveloped locations are revised due to changes in our estimated proved undeveloped oilfuture development plans, including changes to proposed lateral lengths, development spacing and natural gas reserves for the years ended December 31, 2010, 2011 and 2012:timing of development.

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

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

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

As of December 31, 2012,2013, our proved undeveloped reserves included 26.98.1 MMBbls of oil and 107.8108.4 Bcf of natural gas, for a total of 269.3157 Bcfe of undeveloped reserves. Approximately 16.4 MMBblsAll of our undeveloped oil reserves   and 335 Bcf of natural gas of our proved undeveloped reserves at December 31, 2012 were associated with the future development of our West Texas properties that we acquired in December 2011 and an additional 10.5 MMBbls of oil and 7 Bcf of natural gas were associated with our Eagle Ford shaleEagleville properties in South Texas. The proved undeveloped reserves associated with our Haynesville orand Bossier shale properties represented approximately 87 Bcf of our proved undeveloped natural gas reserves at December 31, 2013. The remaining proved undeveloped natural gas reserves are primarily associated with developing reserves in our Wilcox and Vicksburg reservoirs in South Texas. In 2013, we focused on drilling oil properties due to the weak natural gas prices. 28 of the Eagle Ford shale wells we drilled in 2013 resulted in conversions of proved undeveloped reserves to proved developed producing reserves at December 31, 2013. Our proved undeveloped oil reserves decreased by 2.4 MMBbls during 2013. This decrease was primarily due to converting 3.0 MMBbls of our proved undeveloped oil reserves to developed in 2013 and new reserves additions of 0.6 MMBbls. Our proved undeveloped natural gas reserves increased by 33 Bcf at December 31, 2013 as compared with December 31, 2012. This increase was primarily related to reserve additions of 36 Bcf of natural gas which were partially offset by undeveloped reserves converted to developed reserves of 3 Bcf.

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As of December 31, 2012, our proved undeveloped reserves included 10.5 MMBbls of oil and 75 Bcf of natural gas, for a total of 138 Bcfe of undeveloped reserves. All of our undeveloped oil reserves and 7 Bcf of natural gas were associated with our Eagleville shale properties in South Texas. The proved undeveloped natural gas reserves associated with our Haynesville and Bossier shale properties represented approximately 55 Bcf of our total natural gas proved undeveloped reserves at December 31, 2012. The remaining proved undeveloped reserves are primarily associated with developing reserves in our Cotton Valley and Hosston sand reservoirs in East Texas/North Louisiana and theour Wilcox and Vicksburg reservoirs in South Texas. In 2012, we focused on drilling oil propertieswells due to the weak natural gas prices. Seven of the Eagle Ford shale wells and four of the Wolfbone shale oilEagleville  wells we drilled in 2012 resulted in conversions of proved undeveloped reserves to proved developed producing reserves at December 31, 2012. Undeveloped natural gas reserves originally expected to be converted to developed reserves in 2012 were removed from our proved reserves due to the low natural gas prices during 2012.

Our oil proved undeveloped reserves increased by 22.43.8 MMBbls during 2011.2012. This increase was primarily due to our acquisitiondrilling program which added 8.1 MMBbls in the Eagle Ford shale.  Sales of oil reserves in 2012 of 3.1 MMbls and conversions of proved undevelopeddeveloped oil reserves in West Texas of 17.01.3 MMBbls proved undeveloped reserves additions of 4.7 MMBblspartially offset the increase from our Eagle Ford shale properties and 0.7 MMBbls of oil additions and revisions on our other properties.reserve adds.  Our natural gas proved undeveloped reserves increaseddecreased by 49459 Bcf during 2011.2012. This increasedecrease was primarily related to our successful Haynesville and Bossier shale drilling program which added 44 Bcfthe decline of natural gas reserves, our acquisition in West Texasprices which added 34 Bcf and we had other additions of approximately 36 Bcf. Our proved undeveloped natural gas reserves additions were partially offset by conversions to proved developed reserves of approximately 40 Bcf during 2011 and other downward revisions to previous estimates of approximately 23 Bcf.

As of December 31, 2011, our proved undeveloped reserves included 23.7 MMBbls of oil and 568caused 465 Bcf of natural gas, for a total of 710 Bcfe of undeveloped reserves. Approximately 17.0 MMBbls of oil and 34 Bcf of natural gas of our proved undeveloped reserves at December 31, 2011 were associated with the future development of our West Texas properties that we acquired in December 2011 and an additional 6.0 MMBbls of oil and 5 Bcf of natural gas were associated with our Eagle Ford shale properties in South Texas. The proved undeveloped natural gas reserves associated with our Haynesville or Bossier shale properties represented approximately 425 Bcf of our total natural gas proved undeveloped reserves at December 31, 2011. to become uneconomical under the natural gas prices used to determine proved reserves in 2012.

The remainingfollowing table presents the changes in our estimated proved undeveloped oil and natural gas 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. Duringfor the yearyears ended December 31, 2011, the price of oil increased significantly,2012 and the value of oil relative to natural gas on a heating equivalent basis widened to historic levels. This, coupled with a growing over-supply of natural gas in the United States, caused us to change2013: