UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

 

Commission File No. 0-16741

 

COMSTOCK RESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

 

(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 o

 

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 o     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 o

 

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.  þ

 

Indicate by check mark whether the registrant is a large accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” 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 o     No þ

 

As of March 15, 2006, there were 42,970,762 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 the common stock on the New York Stock Exchange on June 30, 2005 (the last business day of the registrant’s most recently completed second fiscal quarter), was $1.0 billion.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Proxy Statement for the 2006 Annual Meeting of Stockholders to be held

May 10, 2006 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, 2005

 

CONTENTS

 

 

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:

 

 

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.

 

“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.

 

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

 

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

 

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

 

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

 

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

 

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

 

“Oil” means crude oil or condensate.

 

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

 

“PV 10 Value” means the present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with the Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. This amount is the same as the standardized measure of discounted future net cash flows related to proved oil and natural gas reserves except that it is determined without deducting future income taxes.

“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.

 

“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 should estimates for proved undeveloped reserves be 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.

 

“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.

 

General

 

Comstock Resources, Inc. is a Nevada corporation whose common stock is listed and traded on the New York Stock Exchange and is engaged in the acquisition, development, production and exploration of oil and natural gas.

 

Our oil and natural gas operations are concentrated in the East Texas/North Louisiana, Southeast Texas, South Texas and Mississippi regions. In addition, we have properties in other regions in Arkansas, Kansas, Kentucky, New Mexico and Oklahoma. We also own 48% of Bois d’Arc Energy, Inc. (“Bois d’Arc Energy”), a publicly-held company which conducts exploration, development and production operations in state and federal waters of the Gulf of Mexico. Our onshore oil and natural gas properties are estimated to have proved reserves of 504.7 Bcfe with an estimated PV 10 Value of $1.6 billion as of December 31, 2005 and a standardized measure of discounted future net cash flows of $1.1 billion (see note 1 on page 13 for a discussion of our PV 10 Value and our standardized measure of discounted future net cash flows). Our proved oil and natural gas reserve base is 86% natural gas and 59% proved developed on a Bcfe basis as of December 31, 2005. The proved reserves attributable to our 48% ownership in Bois d’Arc Energy were 155.0 Bcfe with an estimated PV10 value of $0.9 billion as of December 31, 2005 and a standardized measure of discounted future net cash flows of $0.6 billion. Bois d’Arc Energy’s reserves are 64% natural gas and 83% proved developed on a Bcfe basis as of December 31, 2005.

 

Our proved reserves at December 31, 2005 and our 2005 average daily production are summarized below:

 

 

 

 

Strengths

 

High Quality Properties.  Our onshore operations are focused in four primary operating areas, the East Texas/North Louisiana, Southeast Texas, South Texas and Mississippi regions, which account for approximately 51%, 17%, 10% and 9% of our proved reserves, respectively. We have favorable operating costs which results in us having high cash margins. Finally, our properties have an average reserve life of approximately 15.2 years and have extensive development and exploration potential.

 

Successful Exploration and Development Program.  In 2005, we spent $122.2 million on the exploration and development of our onshore oil and natural gas properties for development drilling, recompletions, workovers, abandonment and production facilities. Overall, we drilled 72 development wells, 48.4 net to us, with a 100% success rate. We also drilled three exploratory wells, 1.4 net to us. Only one of the three wells was successful.

 

Successful Acquisitions.  We have had significant growth over the years as a result of acquisitions. Since 1991, we have added 888.5 Bcfe of proved oil and natural gas reserves from 33 acquisitions at an average cost of $0.98 per Mcfe. In 2005 we acquired 121.5 Bcfe of proved oil and natural gas reserves for $201.8 million. Our application of strict economic and reserve risk criteria have enabled us to successfully evaluate and integrate acquisitions.

Efficient Operator.  We operate 76% of our proved onshore oil and natural gas reserve base as of December 31, 2005 and Bois d’Arc Energy operates 98% of its proved oil and natural gas reserve base as of December 31, 2005. This allows us to control operating costs, the timing and plans for 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.

 

Business Strategy

 

Acquire High Quality Properties at Attractive Costs.  We have a successful track record of increasing our oil and natural gas reserves through opportunistic acquisitions. Since 1991, we have added 888.5 Bcfe of proved oil and natural gas reserves from 33 acquisitions at a total cost of $867.6 million, or $0.98 per Mcfe. The acquisitions were acquired at an average of 61% of their PV 10 Value in the year the acquisitions were completed. In 2005 we acquired 121.5 Bcfe of proved oil and natural gas reserves for $201.8 million or $1.66 per Mcfe. The PV 10 Value of the acquired reserves in 2005 was $355.3 million. We apply strict economic and reserve risk criteria in evaluating acquisitions. 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.

 

Exploit Existing Reserves.  We seek to maximize the value of our oil and natural gas properties by increasing production and recoverable reserves through active workover, recompletion and exploitation activities. We utilize advanced industry technology, including 3-D seismic data, improved logging tools, and formation stimulation techniques. During 2005, we spent approximately $87.3 million to drill 72 onshore development wells, 48.4 net to us, all of which were successful. In addition, we spent approximately $17.7 million for leasehold costs and for recompletion and workover activities. Our business plan in 2006 will focus on developing our East Texas/North Louisiana and Mississippi properties. We have budgeted $179.0 million for development drilling and for recompletion and workover activities in 2006 in all of our regions.

 

Pursue Exploration Opportunities.  We conduct exploration activities to grow our reserve base and to replace our production each year. Most of our exploration efforts are conducted through Bois d’Arc Energy, Inc. In addition to Bois d’Arc Energy’s exploration program we have budgeted $21.0 million for exploration in 2006 primarily in our South Texas region.

 

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. Consequently, we have a significant degree of flexibility to adjust the level of such expenditures according to market conditions. We anticipate spending approximately $200.0 million on our onshore development and exploration projects in 2006. We intend to primarily use operating cash flow to fund our development and exploration expenditures in 2006. We may also make additional property acquisitions in 2006 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.

Primary Operating Areas

 

The following table summarizes the estimated proved oil and natural gas reserves for our twenty largest fields as of December 31, 2005:

 

 

 

East Texas/North Louisiana

 

Approximately 51% or 258.6 Bcfe of our proved reserves are located in East Texas and North Louisiana where we own interests in 670 producing wells, 324.8 net to us, in 31 field areas. We operate 334 of these wells. The largest of our fields in this region are the Beckville, Gilmer, Blocker, Cadeville, Darco, Logansport, Douglass, Waskom, Drew, Longwood and Lisbon fields. Production from this region averaged 38.7 MMcf of natural gas per day and 266 barrels of oil per day during 2005. Most of the reserves in this area produce from the Cretaceous aged Travis Peak/Hosston formation and the Jurassic aged Cotton Valley formation. The total thickness of these formations range from 2,000 to 4,000 feet of sand, shale and limestone sequences in the East Texas Basin and the North Louisiana Salt Basin, at depths ranging from 6,000 to 12,000 feet. In 2005, we spent $71.5 million drilling 52 wells, 40.2 net to us, and $8.6 million on workovers and recompletions in this region. We have budgeted approximately $134.0 million in 2006 for development activities in this region.

 

Beckville

 

Our properties in the Beckville field, located in Panola and Rusk Counties, Texas, have proved reserves of 76.2 Bcfe which represents approximately 15% of our total reserves. We operate 107 wells in this field and own interests in six additional wells for a total of 113 wells, 84.6 net to us. During December 2005, production attributable to our interest from this field averaged 20.2 MMcf of natural gas per day and 11 barrels of oil per day. The Beckville field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet.

 

Gilmer

 

We own interests in 73 natural gas wells, 27.7 net to us, in the Gilmer field in Upshur County in East Texas. These wells produce primarily from the Cotton Valley Lime formation at a depth of approximately 11,500 to 12,000 feet. Proved reserves attributable to our interests in the Gilmer field are 36.1 Bcfe which represents 7% of our total reserve base. During December 2005, production attributable to our interest from this field averaged 6.1 MMcf of natural gas per day and 75 barrels of oil per day.

 

Blocker

 

Our proved reserves of 35.9 Bcfe in the Blocker field located in Harrison County, Texas represent approximately 7% of our total reserves. We own interests in 41 wells, 39.8 net to us, and operate 40 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 8.8 MMcf of natural gas and 85 barrels of oil. Most of this production is from the Cotton Valley formation between 8,500 and 10,100 feet.

 

Cadeville

 

Our proved reserves of 15.9 Bcfe in the Cadeville field located in Ouachita Parrish, Louisiana represent approximately 3% of our total reserves. We own interests in 5 wells, 2.0 net to us, and operate 2 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 0.2 MMcf of natural gas. This production is primarily from the Cotton Valley formation between 9,800 and 10,700 feet. We have six proved undeveloped locations in this field.

 

Darco

 

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 14.6 Bcfe in the Darco Field represent approximately 3% of our total reserves. We own interests in 4 wells, 3.0 net to us, and operate all of these wells. During December 2005, net daily production attributable to our interest from this field averaged 0.7 MMcf of natural gas and 7 barrels of oil.

 

Logansport

 

The Logansport field produces from multiple sands in the Hosston formation at an average depth of 8,000 feet and is located in DeSoto Parish, Louisiana. Our proved reserves of 14.3 Bcfe in the Logansport field represent

approximately 3% of our total reserves. We own interests in 88 wells, 42.2 net to us, and operate 46 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 2.4 MMcf of natural gas and 7 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 from 9,200 to 10,300 feet. Our proved reserves of 10.5 Bcfe in the Douglass field represent approximately 2% of our total reserves. We own interests in 15 wells, 8.5 net to us, and operate 9 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 1.0 MMcf of natural gas.

 

Waskom

 

The Waskom field, located in Harrison and Panola Counties in Texas, represents approximately 2% (8.8 Bcfe) of our proved reserves as of December 31, 2005. We own interests in 54 wells in this field, 27.7 net to us, and operate 29 wells in this field. During December 2005, net daily production attributable to our interest averaged 0.9 MMcf of natural gas and 28 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.

 

Drew

 

Our proved reserves of 7.8 Bcfe in the South Drew field located in Ouachita Parrish, Louisiana represent approximately 2% of our total reserves. Production from this field is from the Cotton Valley formation between 9,000 and 9,600 feet. We own interests in 6 wells, 4.4 net to us, and operate 5 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 0.8 MMcf of natural gas and 12 barrels of oil.

 

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 26 wells in this field, 20.8 net to us, and operate 22 wells in this field. Our proved reserves of 5.6 Bcfe in the Longwood field represent approximately 1% of our total reserves. During December 2005, net daily production attributable to our interest from this field averaged 0.9 MMcf of natural gas and 22 barrels of oil.

 

Lisbon

 

Our proved reserves of 5.0 Bcfe in the Lisbon field, located in Claiborne Parrish, Louisiana, represent approximately 1% of our total reserves. Production from this field is from the Cotton Valley formation between 8,500 and 9,400 feet. We own interests in 11 wells, 6.3 net to us, and operate 9 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 0.2 MMcf of natural gas and 2 barrels of oil.

 

Southeast Texas

 

Approximately 17.4% or 87.6 Bcfe of our proved reserves are located in Southeast Texas, where we own interests in 87 producing wells, 49.7 net to us, and operate 63 of these wells. Net daily production rates from the area averaged 17.5 MMcf of natural gas and 449 barrels of oil during 2005. We spent $16.0 million in the Southeast Texas region in 2005, primarily for the “Big Sandy” exploration well which was unsuccessful. In 2006, we plan to spend $2.9 million for development activity in this region. Substantially all of the reserves in this region are in the Double A Wells field area in Polk County, Texas and the Sugar Creek field in Tyler County, Texas.

Double A Wells

 

The Double A Wells field is our largest field area with total estimated proved reserves of 77.7 Bcfe, which is 15% of our total reserves. We own interests in and operate 61 producing wells, 30.9 net to us, in this field in Polk County, Texas. Net daily production from the Double A Wells area averaged 15.0 MMcf of natural gas and 369 barrels of oil during December 2005. These wells typically produce from the Woodbine formation at an average depth of 14,300 feet.

 

Sugar Creek

 

Our proved reserves of 8.2 Bcfe in the Sugar Creek field located in Tyler County, Texas represent approximately 2% of our total reserves. We own interests in 4 wells, 2.6 net to us, and operate 2 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 0.5 MMcf of natural gas and 8 barrels of oil. Production is from the Woodbine formation between 11,000 to 11,200 feet.

 

South Texas

 

Approximately 10%, or 49.4 Bcfe, of our proved reserves are located in South Texas, where we own interests in 291 producing wells, 70.2 net to us. We own interests in ten fields in the region, the largest of which are the J.C. Martin, North Markham, and Lopeno fields. Net daily production rates from the area averaged 10.3 MMcf of natural gas and 205 barrels of oil during 2005. We spent $12.4 million in this region in 2005 to drill 10 wells, 3.5 net to us, and for other development activity. In 2006, we plan to spend approximately $28.0 million primarily for development and exploration activity in this region.

 

J.C. Martin

 

Our largest field in South Texas is the J.C. Martin field which is located in the structurally complex and highly prolific Wilcox Lobo trend in Zapata County, Texas on the Mexico border. We own interests in 90 wells in this field, 14.4 net to us, with proved reserves of 15.3 Bcfe or 3% of our total reserves. During December 2005, net daily production attributable to our interest from this field averaged 3.9 MMcf of natural gas. This field produces primarily from Eocene Wilcox Lobo sands at depths ranging from 7,000 to 9,000 feet. The Lobo section is characterized by geopressured, multiple pay sands occurring in a highly faulted area.

 

North Markham

 

The North Markham/North Bay City field is located in Matagorda County, Texas. We own interests in and operate 22 producing wells, 22.0 net to us, in the Ohio-Sun Unit. The field’s estimated proved reserves of 12.6 Bcfe represent 3% of our total reserves. The field’s active wells produce from more than twenty reservoirs of Oligocene Frio age at depths ranging from 6,500 to 9,000 feet. During December 2005, net daily production attributable to our interests from this field average 85 barrels of oil and 0.5 MMcf of gas per day.

 

Lopeno

 

Our proved reserves of 4.8 Bcfe in the Lopeno field represent approximately 1% of our total reserves. We own interests in 26 wells, 5.2 net to us, and operate 3 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 0.5 MMcf of natural gas and 3 barrels of oil.

 

Mississippi

 

Our operations in the Mississippi region are mainly located within the Laurel field, located in Jones County, Mississippi near a structurally complex salt dome. We own interests in and operate 45 producing, wells, 42.3 net to us, in the Laurel field. This field’s estimated proved reserves of 43.7 Bcfe represent 9% of our total reserves. The field produces from more than 42 horizons that range in depth from 6,600 feet in the Stanley Sand to 13,100 feet in the Middle Hosston formation. Recovery of high viscosity crude oil from this field is being enhanced through waterflood operations. During December 2005, net daily production attributable to our interests in this field

averaged 1,385 barrels of oil per day. In 2006, we plan to drill and complete 16 wells, 12.0 net to us, and spend approximately $30.0 million for development and exploration activity in this region.

 

Other Regions

 

Southwest Morse

 

Located in Hutchinson County, Texas, the Southwest Morse field is situated on the edge of the greater Hugoton Field producing complex. Production is from the structurally trapped, underpressured Brown Dolomite formation. The Brown Dolomite reservoir is typically encountered at depths of 2,900 to 3,400 feet. Our proved reserves of 7.5 Bcfe in the Southwest Morse field represent approximately 2% of our total reserves. We own interests in 38 wells, 37.1 net to us, and operate 37 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 1.3 MMcf of natural gas.

 

New Albany Shale Gas

 

The New Albany Shale Gas field is located in north-central Kentucky immediately north of the regionally extensive Rough Creek Fault Zone. Gas is produced from fractured Devonian New Albany Shale. The New Albany is generally about 100 feet in thickness and is found at approximately 850 feet from the surface. Our proved reserves of 16.8 Bcfe in this field represent approximately 3% of our total reserves. We own interests in and operate 95 wells, 85.5 net to us. During December 2005, net daily production attributable to our interest from this field averaged 0.9 MMcf of natural gas.

 

San Juan

 

Our San Juan Basin properties are located in the west-central portion of the basin in San Juan County, New Mexico. Historically, production has been from multiple sands of the Cretaceous Dakota formation and the prolific Fruitland Coal seams. The Dakota is generally found at about 6,000 feet with the shallower Fruitland seams generally encountered at 2,500 to 3,000 feet. Recent advances in drilling and stimulation procedures have resulted in additional tight gas zones in the intervening Mesaverde and Mancos Shale being targeted. Our proved reserves of 14.7 Bcfe in the San Juan field represent approximately 3% of our total reserves. We own interests in 87 wells, 12.8 net to us. During December 2005, net daily production attributable to our interest from this field averaged 1.2 MMcf of natural gas and 5 barrels of oil.

 

Gulf of Mexico and Bois d’Arc Energy

 

Prior to July 2004, substantially all of our exploration activities in the Gulf of Mexico were conducted under a joint exploration venture with Bois d’Arc Offshore, Ltd. and its principals, which we collectively refer to as “Bois d’Arc.” Under the exploration venture, Bois d’Arc was responsible for generating exploration prospects in the Gulf of Mexico. From 1997 when the exploration venture was commenced until July 16, 2004 when it was terminated, we participated in drilling approximately 40 exploratory wells to test prospects generated under the exploration venture. Of these exploratory wells drilled, 34 or 85% were successful discoveries. In July 2004, we together with Bois d’Arc and certain participants in their exploration activities, which are collectively referred to as the “Bois d’Arc Participants,” formed Bois d’Arc Energy, LLC to replace the joint exploration venture. We and each of the Bois d’Arc Participants contributed to Bois d’Arc Energy substantially all of our respective Gulf of Mexico related assets and assigned our related liabilities, including certain debt, in exchange for equity interests in Bois d’Arc Energy. We contributed interests in our offshore oil and natural gas properties and assigned $83.2 million of related debt in exchange for an approximately 60% ownership interest in Bois d’Arc Energy. Each of the Bois d’Arc Participants contributed its interest in commonly owned Gulf of Mexico properties as well as ownership of Bois d’Arc Offshore, Ltd., the operator of the properties, and assigned in the aggregate $28.2 million of related liabilities in exchange for an approximately 40% aggregate ownership interest in Bois d’Arc Energy. The Bois d’Arc Participants also received $27.6 million in cash to equalize the amount that our debt exceeded our proportional share of the liabilities assigned. We were also reimbursed $12.7 million for advances made under the joint exploration venture for undrilled prospects.

We initially owned 60% of Bois d’Arc Energy, and we accounted for our share of the Bois d’Arc Energy financial and operating results using proportionate consolidation accounting until Bois d’Arc Energy converted into a corporation and completed its initial public offering in May 2005. Subsequent to the conversion of Bois d’Arc Energy into a corporation and the public offering, we own 48% of Bois d’Arc Energy and we changed our accounting method for our investment in Bois d’Arc Energy to the equity method. Accordingly, effective May 10, 2005 our consolidated financial results no longer include our proportionate interest in the Bois d’Arc Energy operating results.

 

Bois d’Arc Energy owns interests in 46 gross (27.8 net) oil wells and 65 gross (46.8 net) gas wells in the Gulf of Mexico. Bois d’Arc Energy operates 91 of these 111 wells. Thirty-four of these wells were shut-in on December 31, 2005 waiting on third party pipelines to return to service. Bois d’Arc Energy also owns 203,301 (143,519 net) developed acres and 148,438 undeveloped acres in which it owns a 100% interest. Forty-nine percent of the acreage is held by production and 83% of the undeveloped acreage expires between 2008 and 2010.

 

Major Property Acquisitions

 

As a result of our acquisitions, we have added 888.5 Bcfe of proved oil and natural gas reserves since 1991 including 121.5 Bcfe we acquired in 2005.

 

Our largest acquisitions are the following:

 

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 in the acquisition include the Cadeville, Darco, Douglass, Drew and Laurel fields. The acquisition was funded with proceeds from a public stock offering completed in April 2005 and borrowings under our bank credit facility.

 

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 include 165 active wells, of which 69 are operated by us. Major fields acquired in the acquisition include Southwest Morse and San Juan fields. The acquisition was funded by borrowings under our bank credit facility.

 

DevX Energy Acquisition.  In December 2001, we completed the acquisition of DevX Energy, Inc. (“DevX”) 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. As a result of the acquisition of DevX, we acquired interests in 600 producing oil and natural gas wells located onshore primarily in East and South Texas, Kentucky, Oklahoma and Kansas. Major fields acquired in the acquisition include the Gilmer field in East Texas, the J.C. Martin and Lopeno fields in South Texas and the New Albany Shale Gas field in Kentucky. DevX’s properties had 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, we 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.

 

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 Southeast 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 Beckville, Logansport, Waskom, and Longwood fields. The net proved reserves acquired in this acquisition were estimated at 0.8 MMBbls of oil and 104.7 Bcf of natural gas.

 

Oil and Natural Gas Reserves

 

The following table sets forth our estimated proved oil and natural gas reserves and the PV10 Value as of December 31, 2005:

 

 

 

 

The following table sets forth our 48% ownership interest in of Bois d’Arc Energy’s estimated proved oil and natural gas reserves and the PV 10 Value as of December 31, 2005:

 

 

 

Proved oil and gas reserves are 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). Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are 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.

 

The PV 10 Value and standardized measure of discounted future net cash flows was determined based on the market prices for oil and natural gas on December 31, 2005. The market price for our oil production on December 31, 2005, after basis adjustments, was $49.17 per barrel as compared to $42.17 per barrel on December 31, 2004. The market price received for our natural gas production on December 31, 2005, after basis adjustments, was $8.27 per Mcf as compared to $5.86 per Mcf on December 31, 2004.

 

We did not provide estimates of total proved oil and natural gas reserves during the years ended December 31, 2003, 2004 or 2005 to any federal authority or agency, other than the SEC.

 

Drilling Activity Summary

 

During the three-year period ended December 31, 2005, we drilled development and exploratory wells as set forth in the table below.

 

The wells drilled in 2005 exclude the 22 wells drilled by Bois d’Arc Energy. In 2005 Bois d’Arc Energy drilled the following wells:

 

 

In 2006 to the date of this report, we have drilled 23 development wells, 14.3 net to us. Twenty-two of the wells were successful and one (1.0 net to us) was a dry hole. As of the date of this report, we have seven development wells, 2.9 net to us, that are in the process of drilling.

 

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, 2005:

 

 

 

 

We operate 628 of the 1,554 producing wells presented in the above table. Bois d’Arc Energy operates 47 of its producing wells.

Acreage

 

The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2005. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.

 

 

 

 

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 or by payment of delay rentals.

 

Markets and Customers

 

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

 

Our oil production is sold at prices tied to the spot oil markets. Our natural gas production is primarily sold under short-term contracts and priced on first of the month index prices or on daily spot market prices. Approximately 76% of our 2005 natural gas sales were priced utilizing index prices and approximately 24% were priced utilizing daily spot prices. Two subsidiaries of Shell Oil Company accounted for approximately 15% of our total 2005 sales. Sales to BP Energy Company comprised approximately 12% of our total 2005 sales. The loss of any of the foregoing 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.

 

Bois d’Arc Energy’s oil production is sold at prices tied to the spot oil markets. Bois d’Arc Energy’s natural gas production is sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. Approximately 43% of Bois d’Arc Energy’s 2005 natural gas sales were priced utilizing index prices and 57% were priced utilizing daily spot prices. Shell Trading (US) Company was Bois d’Arc Energy’s most significant oil purchaser in 2005, accounting for approximately 33% of its total 2005 oil and gas sales. BP Energy Company was Bois d’Arc Energy’s most significant natural gas purchaser in 2005, accounting for approximately 49% of Bois d’Arc Energy’s total 2005 oil and gas sales. The loss of any of the foregoing customers would not have a material adverse effect on Bois d’Arc Energy as there is an available market for its crude oil and natural gas production from other purchasers.

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.

 

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 wellhead sales of natural gas, effective January 1, 1993. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, in the future Congress could reenact price controls or enact other legislation with detrimental impact on many aspects of our business.

 

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. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the results of Order No. 636 and related initiatives have been to substantially reduce or eliminate the traditional role of interstate pipelines as wholesalers of natural gas in favor of providing storage and transportation services.

 

In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERC’s pricing policy by waiving price ceilings for short-term released capacity for an experimental period, and effected changes in the FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. While most major aspects of Order No. 637 have been upheld on judicial review, certain issues such as capacity segmentation and right of first refusal are pending further consideration by the FERC. We cannot predict what action the FERC will take on these matters in the future or whether the FERC’s actions will survive further judicial review.

 

Intrastate natural gas regulation 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 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 recently pursued by the FERC, Congress and state regulatory authorities will continue.

 

Oil and Natural Gas Liquids Transportation Rates.  Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport

and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.

 

The regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed than the FERC’s regulation of natural gas pipelines under the NGA. 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 market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, issued in October 1993, the FERC implemented regulations generally grandfathering all previously unchallenged interstate pipeline rates and made these rates subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus one percent. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge a market-based rate if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline. As provided for in Order No. 561, in July 2000, the FERC issued a Notice of Inquiry seeking comment on whether to retain or to change the existing oil rate-indexing method. In December 2000, the FERC issued an order concluding that the rate index reasonably estimated the actual cost changes in the pipeline industry and should be continued for another five-year period, subject to review in July 2005. In February 2003, on remand of its December 2000 order from the D.C. Circuit, the FERC increased its index slightly. A challenge to FERC’s remand order was denied by the D.C. Circuit in April 2004.

 

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

 

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

 

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

 

We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements 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 cost, 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 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.

 

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 National Environmental Policy Act, the Coastal Zone Management Act, 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.

 

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, plug 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 32,896 square feet at a monthly rate of $61,680. The lease expires on July 31, 2014. We also own production offices and pipe yard facilities near Marshall and Livingston, Texas, Logansport, Louisiana, Guston, Kentucky and Laurel, Mississippi.

 

Employees

 

As of December 31, 2005, we had 89 employees and utilized contract employees for certain of our field operations. We consider our employee relations to be satisfactory.

Directors, Executive Officers and Other Management

 

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 June 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. He received B.B.A., M.S. and J.D. degrees from Baylor University in 1978, 1980 and 1981, respectively. Mr. Allison also serves as Chairman of the board of directors of Bois d’Arc Energy, Inc. and currently serves on the Board of Regents for Baylor University and on the Advisory Board of the Salvation Army in Dallas, Texas.

 

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. Mr. Burns also serves as Senior Vice President, Chief Financial Officer, Secretary and a director of Bois d’Arc Energy, Inc. From 1982 to 1990, Mr. Burns was employed by the public accounting firm, Arthur Andersen LLP. During his tenure with Arthur Andersen LLP, Mr. Burns worked primarily in the firm’s oil and gas audit practice. Mr. Burns received B.A. and M.A. degrees from the University of Mississippi in 1982 and is a Certified Public Accountant.

 

Mack D. Good was appointed our Chief Operating Officer in 2004. From 1999 to 2004, he served as Vice President of Operations. From August 1997 until February 1999, Mr. Good served as our district engineer for the East Texas/North Louisiana region. From 1983 until July 1997, Mr. Good was with Enserch Exploration, Inc. serving in various operations management and engineering positions. Mr. Good received a B.S. of Biology/Chemistry from Oklahoma State University in 1975 and a B.S. of Petroleum Engineering from the University of Tulsa in 1983. He is a Registered Professional Engineer in the State of Texas.

 

Stephen E. Neukom has been our Vice President of Marketing since December 1997 and has served as our manager of crude oil and natural gas marketing since December 1996. From October 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.

 

Richard G. Powers joined us as Land Manager in October 1994 and has been our Vice President of Land since December 1997. Mr. Powers has over 20 years of experience as a petroleum landman. Prior to joining us, Mr. Powers

was employed for 10 years as land manager for Bridge Oil (U.S.A.), Inc. and its predecessor Pinoak Petroleum, Inc. Mr. Powers received a B.B.A. degree from Texas Christian University in 1976.

 

Daniel K. Presley has been our Vice President of Accounting since December 1997 and has been with us since December 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. from Texas A & M University in 1983.

 

Richard D. Singer joined us in June 2005 as Vice President of Financial Reporting. Mr. Singer has over 25 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 March 2004 to May 2005 and as assistant controller for Santa Fe International Corporation from July 1988 to December 2002. Mr. Singer received a B.S. degree from the Pennsylvania State University in 1976 and is a Certified Public Accountant.

 

Michael W. Taylor has been our Vice President of Corporate Development since December 1997 and has served us in various capacities since September 1994. Mr. Taylor has 32 years of experience in the oil and gas business. For 15 years prior to joining us, he had been an independent oil and gas producer and petroleum consultant. Before that time, he worked in various engineering and executive capacities for a major oil company, a small independent producer and an international oil and gas consulting company. Mr. Taylor is a Registered Professional Engineer in the State of Texas and he received a B.S. degree in Petroleum Engineering from Texas A & M University in 1974.

 

Outside Directors

 

David K. Lockett has served as a director since July 2001. Mr. Lockett has been a Vice President of Dell Inc. and has managed Dell’s Small and Medium Business Group since 1996. Mr. Lockett has been employed by Dell Inc. for the last 13 years and has spent the past 25 years in the technology industry. Mr. Lockett also serves as a director of Bois d’Arc Energy, Inc. Mr. Lockett received a B.B.A. degree from Texas A&M University in 1976.

 

Cecil E. Martin, Jr. has served as a director since October 1989. 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 also serves as a director of Bois d’Arc Energy, Inc. and was recently appointed to the board of directors of Crosstex Energy, Inc. and Crosstex Energy, L.P. Mr. Martin holds a B.B.A. degree from Old Dominion University and is a Certified Public Accountant.

 

David W. Sledge has served as a director since May 1996. Mr. Sledge is presently managing personal oil and gas investments. He served as an area operations manager for Patterson-UTI Energy, Inc. from May 2004 until January 2006. From October 1996 until May 2004, Mr. Sledge managed his personal investments in oil and gas exploration activities. 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. Mr. Sledge also serves as a director of Bois d’Arc Energy, Inc. 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 1981. Ms. Underwood holds B.S. and J.D. degrees from Emory University and practiced law at an Atlanta, Georgia based law firm before joining Underwood Development Corporation in 1981. Ms. Underwood is involved civically in the Dallas community and currently serves on the boards of the Presbyterian Hospital of Dallas Foundation, the Dallas Historical Society and the Dallas County Advisory Board of the Salvation Army.

 

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 450 Fifth Street, N.W., 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 are important factors, among others, that 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:

 

 

Any continued and extended decline in the price of crude oil or natural gas will adversely affect:

 

 

We have entered into certain natural gas 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 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.

 

With the increasing oil and natural gas prices, our industry is beginning to experience a shortage of drilling rigs, equipment, supplies and qualified personnel. Costs and delivery times of rigs, equipment and supplies are substantially greater than they were several years ago. In addition, demand for, and wage rates of, qualified drilling rig crews rise with increases in the number of active rigs in service. 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.

 

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

 

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

 

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

 

 

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

 

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics or geographic location than our existing properties. While our current operations are focused in the East Texas/North Louisiana, Southeast Texas, South Texas, Mississippi, the Mid-Continent and other regions, as well as the Gulf of Mexico through our 48% ownership interest in Bois d’Arc Energy we may pursue acquisitions or properties located in other geographic areas.

 

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

 

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

and development costs. Furthermore, while our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

 

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

 

A prospect is a property in which we own an interest or have operating rights and 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.

 

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

 

We had $243.0 million in debt as of December 31, 2005, and our ratio of total debt to total capitalization was approximately 29%.

 

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:

 

 

Our failure to comply with any of these covenants would cause a default under our bank credit facility and the indenture governing our 67/8% senior notes due 2012. 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. 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.

 

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:

 

 

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

 

We could also incur substantial losses as a result of:

 

 

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

 

The oil and natural gas industry is highly competitive in the search for and development and acquisition of reserves. Our competitors for the acquisition, development and exploration of oil and natural gas properties and capital to finance such activities, include companies that have greater financial and personnel resources than we do.

These resources could allow those competitors to price their products and services more aggressively than we can, which could hurt our profitability. Moreover, our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to close transactions in a highly competitive environment.

 

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

 

If our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advances and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. All of these factors may inhibit our ability to acquire additional prospects and compete successfully in the future.

 

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

 

We expect to expend substantial capital in the acquisition of, exploration for and development of oil and natural gas reserves. In order to finance these activities, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of non-strategic assets or other means. The issuance of additional equity securities could have a dilutive effect on the value of our common shares. The issuance of additional debt would require that a portion of our cash flow from operations be used for the payment of interest on our debt, thereby reducing our ability to use our cash flow to fund working capital, capital expenditures, acquisitions, dividends and general corporate requirements, which could place us at a competitive disadvantage relative to other competitors. Additionally, if our revenues decrease as a result of lower oil or natural gas prices, operating difficulties or declines in reserves, our ability to obtain the capital necessary to undertake or complete future exploration and development programs and to pursue other opportunities may be limited, which could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could result in a decline in our oil and natural gas reserves.

 

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

 

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

 

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

 

Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve

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

 

As of December 31, 2005, 41% of our total proved reserves are undeveloped and 10% are developed non-producing. These reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced at the time periods we have planned, at the costs we have budgeted, or at all. As a result, we may not find commercially viable quantities of oil and natural gas, which in turn may result in a material adverse effect on our results of operations.

 

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

 

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

 

 

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

 

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

 

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

 

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

 

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

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

 

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

 

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

 

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

 

 

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

 

 

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

 

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

 

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

 

 

 

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

 

 

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

 

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

 

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

 

 

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

 

None.

 

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

 

No matters were submitted to a vote of our security holders during the fourth quarter of 2005.

 

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

 

 

As of March 15, 2006, we had 42,970,762 shares of common stock outstanding, which were held by 353 holders of record and approximately 18,000 beneficial owners who maintain their shares in “street name” accounts.

 

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

 

The following table summarizes certain information regarding our equity compensation plans as of December 31, 2005:

 

 

 

 

The historical financial data presented in the table below as of and for each of the years in the five-year period ended December 31, 2005 are derived from our consolidated financial statements. The financial results are not necessarily indicative of our future operations or future financial results. The data presented below should be read in conjunction with our consolidated financial statements and the notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

Statement of Operations Data: