Bois D Arc Energy (BDE) 10-K 2005 FY Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)
þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2005
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 001-32494

BOIS d’ARC ENERGY, INC.

(Exact name of registrant as specified in its charter)

NEVADA	20-1268553
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

600 Travis Street, Suite 5200, Houston, TX 77002

(Address of principal executive offices including zip code)

(713) 228-0438

(Registrant’s telephone number and area code)

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

Common Stock, $.01 Par Value
(Title of class) New York Stock Exchange
(Name of exchange on which registered)

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

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

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 ofRegulation 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 thisForm 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” inRule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o          Accelerated filer o          Non-accelerated filer þ          

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

As of March 16, 2006, there were 64,145,000 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 $250.7 million.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2006 Annual Meeting of Stockholders to be held
June 2, 2006 are incorporated by reference into Part III of this report.

BOIS d’ARC ENERGY, INC.

ANNUAL REPORT ONFORM 10-K

For the Fiscal Year Ended December 31, 2005

CONTENTS

Item		Page
Part I
	Cautionary Note Regarding Forwarding Looking Statements		2
	Definitions		3
1. and 2.	Business and Properties		5
1A.	Risk Factors		19
1B.	Unresolved Staff Comments		30
3.	Legal Proceedings		30
4.	Submission of Matters to a Vote of Security Holders		30
Part II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		31
6.	Selected Financial Data		32
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		33
7A.	Quantitative and Qualitative Disclosures About Market Risks		45
8.	Financial Statements and Supplementary Data		45
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		46
9A.	Controls and Procedures		46
9B.	Other Information		46
Part III
10.	Directors and Executive Officers of the Registrant		46
11.	Executive Compensation		47
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		47
13.	Certain Relationships and Related Transactions		47
14.	Principal Accountant Fees and Services		47
Part IV
15.	Exhibits and Financial Statement Schedules		47
Subsidiaries
Consent of Ernst & Young LLP
Consent of Lee Keeling and Associates, Inc.
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

1

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

•  the potential for future of undiscovered reserves;

•  the availability of exploration and development opportunities;

•  amount, nature and timing of capital expenditures;

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

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

•  our financial or operating results;

•  cash flow and anticipated liquidity;

•  operating costs such as finding and development costs, lease operating expenses, administrative costs and other expenses;

•  our business strategy; and

•  other plans and objectives for future operations.

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

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

•  the timing and success of our drilling activities;

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

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

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

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

•  our ability to effectively market our oil and natural gas;

•  the availability of rigs, equipment, supplies and personnel;

•  our ability to discover or acquire additional reserves;

•  our ability to satisfy future capital requirements;

•  changes in regulatory requirements;

•  general economic and competitive conditions;

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

•  continued hostilities in the Middle East and other sustained military campaigns and acts of terrorism or sabotage.

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DEFINITIONS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report. Natural gas equivalents and crude oil equivalents are determined using the ratio of six Mcf to one barrel. All references to “us,” “our,” “we” or “Bois d’Arc” mean Bois d’Arc Energy, Inc., including as the successor to Bois d’Arc Energy, LLC and where applicable, its consolidated subsidiaries.

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

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

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

“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 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”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.

“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

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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.

“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%.

“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.

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PART I

ITEMS 1. and 2.   BUSINESS AND PROPERTIES

General

Bois d’Arc Energy, Inc. is a Nevada corporation whose common stock is listed and traded on the New York Stock Exchange. We are a growing independent exploration company engaged in the discovery and production of oil and natural gas in the Gulf of Mexico.

Our operations are concentrated in the Gulf of Mexico. Our oil and natural gas properties are estimated to have proved reserves of 323 Bcfe with an estimated PV 10 Value of $1.9 billion as of December 31, 2005 and a standardized measure of discounted future net cash flows of $1.3 billion (see note 1 on page 10 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 64% natural gas and 83% proved developed on a Bcfe basis as of December 31, 2005. We served as operator for approximately 98% of our properties based on the PV 10 Value of the related proved reserves. In 2005 our daily production was 40.8 MMcf of natural gas and 3,164 barrels of oil or 59.8 MMcfe per day.

Strengths

Experienced Management and Technical Team.  Our management and technical team has an average of 25 years of experience exploring, operating and producing natural gas and oil reserves in the Gulf of Mexico region and has experience in all phases of drilling and completing wells in the Gulf of Mexico.

Substantial Drilling Inventory.  As a result of our experienced technical team and our successful exploration drilling program, we have assembled an inventory of 43 exploratory prospects. Our inventory and our degree of operating control provide us with flexibility in project selection and the timing of our drilling projects. We believe there are opportunities to expand our exploration activities on our existing leasehold acreage position, particularly by exploring the deep shelf, which we define as prospects at geologic and drilling depths greater than 15,000 feet.

Operational Capabilities.  We operate 98% of the PV 10 Value of our properties, and believe that by having operational control, we are able to more effectively control our expenses, capital allocation and the timing and method of exploration and development of our properties.

Technical Approach.  Substantially all of our drilling prospects have been generated internally by our technical team using advanced technology in analyzing, interpreting and visualizing3-D seismic data.

Strong Balance Sheet.  Our debt to total capitalization was 14% at December 31, 2005. We plan to maintain a conservative balance sheet to preserve our ability to execute our exploration program despite volatility of commodity prices.

Business Strategy

Our goal is to increase shareholder value by investing in exploration and development projects that generate attractive rates of return. We seek to achieve this goal through the following strategies:

Grow Through Exploration.  We focus a substantial portion of our capital investments on exploration activities because we believe that, over the long-term, exploration provides attractive risk-weighted rates of return. From the formation of our joint exploration venture in 1997 through December 31, 2005, our exploration program has achieved an average drilling success rate of 73%, with 69 successful exploration wells out of a total of 95 drilled. In 2005, our exploration activities resulted in additions to our proved reserves of 68 Bcfe. These additions were partially offset by 28 Bcfe of downward revisions to our proved reserve estimates, resulting in a net addition to our proved reserves of 40 Bcfe in 2005.

Focus on the Gulf of Mexico Shelf.  We plan to continue to explore for reserves in the Gulf of Mexico shelf. We define the Gulf of Mexico shelf as the area of the Gulf of Mexico extending out to the continental shelf break, which generally occurs at a water depth of approximately 600 feet. This region is a prolific producing area that we

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believe has substantial future exploration potential due to favorable economic and geologic conditions for finding oil and natural gas, including multiple reservoir formations, and comprehensive geologic and seismic databases.

Generate Prospects Internally.  Substantially all of our oil and natural gas prospects are originated and developed internally through the combined efforts of our technical team. Our regional expertise, combined with a rigorous structural and stratagraphic interpretation of3-D seismic data integrated with subsurface mapping techniques, promotes the identification of quality drilling prospects.

Pursue Leasehold Acquisitions.  We have been an active participant in the eight central Gulf of Mexico sales held since 1999, and expect to continue a high level of participation in future sales. Since 1999, we have been the high bidder on 57 out of 72 blocks on which we have bid, representing an 79% success rate. However, we may not be as successful in future lease sales. In addition to bidding on blocks in the Gulf of Mexico lease sales, we actively pursue exploration prospects through farm-in opportunities and acquisitions of producing and non-producing properties that have exploration potential.

Operate Core Properties.  As of December 31, 2005, we served as operator for approximately 98% of our properties, based on the PV 10 Value of our proved reserves. As operator, we can manage all phases of a project’s drilling and development operations. We believe operating allows us to:

•  exercise greater control over the cost, timing and scope of our activities;

•  more effectively utilize our platforms, processing facilities, flowlines and pipelines; and

•  maintain a lower cost structure.

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, including3-D seismic data, improved logging tools, and formation stimulation techniques. During 2005, we spent approximately $77.6 million to drill 11 development wells, 10.2 net to us, of which 9 wells, 8.2 net to us, were successful, representing a success rate of 82%. In addition, we spent approximately $41.7 million in 2005 for production facilities and for recompletion, abandonment and workover activities.

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 $180.0 million on development and exploration projects in 2006. We intend to primarily use operating cash flow to fund our drilling 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.

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Primary Operating Areas

Our properties are located in the outer continental shelf of the Gulf of Mexico in water depths of up to 75 feet. The reservoirs in our properties are generally characterized as having high porosity and permeability, which typically result in high production rates. The following table summarizes the estimated proved oil and natural gas reserves for our 10 largest fields as of December 31, 2005:

	Net Oil		Net Gas							PV 10
	(MBbls)		(MMcf)		MMcfe		%			Value(1)			%
										(in thousands)
Ship Shoal 111 and the Ship Shoal 113 Unit		6,566		64,136		103,530		32	%	$	601,677			31	%
South Pelto 5 and South Timbalier 9, 11 and 16		2,110		27,419		40,082		12	%		256,335			13	%
Ship Shoal 66, 67, 68, 69 and South Pelto 1		3,669		10,225		32,239		10	%		175,193			9	%
Ship Shoal 99, 107, 109 and 110		384		23,855		26,162		8	%		166,778			9	%
Vermilion 51 and South Marsh Island 220		185		21,749		22,857		7	%		162,560			8	%
South Timbalier 29, 30 and 38		1,091		9,149		15,698		5	%		98,446			5	%
South Timbalier 34 and 50 and South Pelto 14 and 15		1,311		7,236		15,099		5	%		69,934			4	%
Vermilion 87, 122 and 127		811		10,099		14,966		5	%		100,322			5	%
South Pelto 22		1,195		6,045		13,212		4	%		52,488			3	%
Ship Shoal 134, 135 and 146		—		11,667		11,667		4	%		86,803			5	%
Other		2,208		14,406		27,655		9	%		157,498			8	%
Total		19,530		205,986		323,167		100	%		1,928,034			100	%
Discounted Future Income Taxes											(645,609	)
Standardized Measure of Discounted Future Net Cash Flows										$	1,282,425

⁽¹⁾ The PV 10 Value excludes future income taxes related to the future net cash flows. The standardized measure of future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax discounted at 10%.

Our Gulf of Mexico operations include properties located offshore of Louisiana and Texas, in state and federal waters of the Gulf of Mexico. We own interests in 67 producing wells, 40.4 net to us. In addition, we have 34 wells, 24.7 net to us, that were shut-in on December 31, 2005 waiting on third party pipelines to return to service. We also have 10 new wells, 9.4 net to us, that are awaiting the installation of production facilities. We operate 91 of the total wells that we own. Production averaged 40.8 MMcf of natural gas per day and 3,164 barrels of oil per day during 2005 or 59.8 MMcfe per day. We spent $77.6 million in 2005 drilling 11 development wells, 10.2 net to us, and $63.0 million drilling 11 exploratory wells, 8.5 net to us. We also spent $41.7 million for production facilities, recompletions, abandonment and workovers and $19.9 million on acquiring exploration acreage and seismic data. In 2006, we plan to spend $180.0 million for development and exploration activities.

Ship Shoal 111 and the Ship Shoal 113 Unit

The Ship Shoal 113 unit is located in federal waters having water depths from 20 to 50 feet, offshore of Terrebonne Parish, Louisiana and is comprised of 33,125 acres of federal leases covering portions of Ship Shoal blocks 93, 94, 112, 113, 114, 117, 118, 119 and 120. This unit was discovered in the late 1940s and has had cumulative production of 946 Bcfe of natural gas. These properties have 70 productive sands occurring at depths from 2,500 to 16,000 feet. We acquired a 50% working interest in these properties in December 2002 and acquired an additional 30% working interest in October 2003. We acquired the adjacent Ship Shoal block 111 in 2005 together with an existing production platform. Since 2003 we have drilled 14 wells (13.0 net to us) in this area. We

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operate the four production platforms and the 16 producing wells (15.0 net to us) comprising these properties. Production from these properties net to our interest averaged 14.5 MMcf of natural gas per day and 1,754 barrels of oil per day, or 25.0 MMcfe per day, during December 2005.

South Pelto 5 and South Timbalier 9, 11, 16

We own interests in 14 producing wells, 9.9 net to us, in South Pelto block 5 and South Timbalier blocks 9, 11 and 16. These blocks are located in Louisiana state waters and in federal waters, offshore of Terrebonne Parish, Louisiana in water depths from 30 to 50 feet. These wells share common production facilities comprised of a four-pile main production platform and a tripod satellite production platform. We acquired our lease position in South Pelto block 5 and South Timbalier block 11 through a farm-in in 1998. We leased adjacent acreage in South Timbalier blocks 9, 11 and 16 from the State of Louisiana from 1998 through 2002. We have drilled 18 wells, including redrills of existing wells (12.7 net to us), in these blocks. These wells have 18 productive sands occurring at depths from 8,000 to 17,000 feet. Production from these properties net to our interest averaged 198 barrels of oil per day, or 1.2 MMcfe per day, during December 2005. Our natural gas production from these properties in December 2005 was shut-in awaiting a third party pipeline to return to service.

Ship Shoal 66, 67, 68, 69 and South Pelto 1

Ship Shoal blocks 66, 67, 68, 69 and South Pelto block 1 are located in Louisiana state waters and in federal waters with depths from 20 to 35 feet, offshore of Terrebonne Parish, Louisiana. These properties produce from ten sands occurring at depths from 9,000 to 13,500 feet. We own interests in 18 wells (9.6 net to us) on Louisiana state leases partially covering Ship Shoal blocks 66 and 67 and South Pelto 1, and federal leases covering Ship Shoal blocks 68 and 69. We acquired these properties in December 1997 from Bois d’Arc Resources and other interest owners. We have drilled 7 wells (6.1 net to us) subsequent to the acquisition. These wells are connected to four production platforms and share common oil terminal facilities. Production from these properties net to our interest averaged 0.7 MMcf of natural gas per day and 447 barrels of oil per day, or 3.3 MMcfe per day, during December 2005.

Ship Shoal 99, 107, 109 and 110

Ship Shoal blocks 99, 107, 109 and 110 are located in federal waters with depths from 20 to 25 feet, offshore of Terrebonne Parish, Louisiana. We acquired these leases in federal lease sales in 2000 and 2001 and subsequently drilled 9 successful wells (6.9 net to us). These wells have 15 productive sands occurring at depths from 8,800 to 12,300 feet. Production from these properties net to our interest averaged 8.4 MMcf of natural gas per day and 224 barrels of oil per day, or 9.7 MMcfe per day, during December 2005.

Vermilion 51 and South Marsh Island 220

Vermilion block 51 and the adjacent block at South Marsh Island 220 are located in federal waters with depths from 10 to 15 feet, offshore of Vermilion Parish, Louisiana. We purchased undrilled leases from another exploration company in 2003 and subsequently drilled five wells (4.2 net to us). These wells have six productive sands occurring at depths from 7,400 to 11,000 feet. These wells produce to a common four-pile production platform. Production from these properties net to our interest averaged 18.9 MMcf of natural gas per day and 41 barrels of oil per day, or 19.1 MMcfe per day, during December 2005.

South Timbalier 29, 30 and 38

South Timbalier blocks 29, 30 and 38 are located in federal waters with depths from 40 to 50 feet, offshore of Terrebonne Parish, Louisiana. We farmed-in this acreage in 2002 and over the next two years drilled four wells (3.0 net to us). These wells have six productive sands occurring at depths from 5,700 to 15,700 feet. These wells are connected to a common four-pile production platform. Our production in December 2005 from these properties was shut-in awaiting a third party pipeline to return to service.

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South Timbalier 34 and 50 and South Pelto 14 and 15

South Timbalier blocks 34 and 50 and the adjacent blocks at South Pelto 14 and 15 are located in federal waters having a water depth of 55 feet, offshore of Terrebonne Parish, Louisiana. These properties have 18 productive sands occurring at depths from 2,000 to 14,000 feet. We own interests in nine producing wells (6.4 net to us) that are connected to a three-platform production complex. We acquired our acreage position by purchasing these blocks and the production facilities from another offshore operator in 1998. Subsequent to the acquisition, we drilled eleven successful wells (8.0 net to us) in these blocks. Production from these properties net to our interest averaged 109 barrels of oil per day, or 0.7 MMcfe per day, during December 2005. Our natural gas production from this area was shut-in during December 2005 awaiting a third party pipeline to return to service.

Vermilion 87, 122 and 127

Vermilion blocks 87, 122 and 127 are located in federal waters with depths from 30 to 70 feet, offshore of Vermilion Parish, Louisiana. We acquired Vermilion block 87 by taking over and completing a well that another offshore operator had drilled and was planning to abandon. We purchased Vermilion block 122 from another operator and leased block 127. We subsequently drilled five wells (3.9 net to us). These wells have 11 productive sands occurring at depths from 6,000 to 12,000 feet and are connected to two production platforms. Production from these properties net to our interest averaged 9.2 MMcf of natural gas per day and 322 barrels of oil per day, or 11.1 MMcfe per day, during December 2005.

South Pelto 22

South Pelto block 22 is located in federal waters with depths from 50 to 60 feet, offshore of Terrebonne Parish, Louisiana. We farmed-in this acreage from another offshore operator in 2003 and subsequently drilled three wells (1.5 net to us) in 2003 and 2004. These wells have 14 productive sands occurring at depths from 13,400 to 17,000 feet. Production from these properties net to our interest averaged 0.9 MMcf of natural gas per day and 204 barrels of oil per day, or 2.1 MMcfe per day, during December 2005.

Ship Shoal 134, 135 and 146

Ship Shoal blocks 134, 135 and 146 are located in federal waters with depths from 30 to 40 feet, offshore of Terrebonne Parish, Louisiana. We acquired our leasehold position in these blocks in the 2001 federal lease sale. We drilled five wells (3.9 net to us) during 2003 and 2004. These properties have nine productive sands occurring at depths from 3,000 to 10,800. Our production from these properties was shut-in during December 2005 awaiting a third party pipeline to return to service.

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Oil and Natural Gas Reserves

The following table sets forth our estimated proved oil and natural gas reserves, which are the estimated quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and the PV 10 Value of our proved oil and natural gas reserves as of December 31, 2005:

	Oil		Gas		Total		PV 10 Value(1)
	(MBbls)		(MMcf)		(MMcfe)		(In thousands)
Proved Developed Producing		4,409		43,310		69,766	$	437,419
Proved Developed Non-producing		10,907		132,529		197,970		1,183,423
Proved Undeveloped		4,214		30,147		55,431		307,192
Total Proved		19,530		205,986		323,167	$	1,928,034
Discounted Future Income Taxes								(645,609	)
Standardized Measure of Discounted Future Net Cash Flows(1)							$	1,282,425

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

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 the standardized measure of discounted future net cash flows of our proved oil and natural gas reserves 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 $57.92 per barrel. The market price received for our natural gas production on December 31, 2005, after basis adjustments, was $10.21 per Mcf.

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Drilling Activity Summary

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

	Year Ended December 31,
	2003				2004				2005
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:
Oil		1		.4		4		3.2		2		1.5
Gas		10		7.4		5		3.8		8		6.4
Dry		—		—		5		3.1		1		0.6
		11		7.8		14		10.1		11		8.5
Development Wells:
Oil		—		—		1		1.0		3		3.0
Gas		7		4.7		9		7.1		6		5.2
Dry		—		—		—		—		2		2.0
		7		4.7		10		8.1		11		10.2
Total Wells		18		12.5		24		18.2		22		18.7

From January 1, 2006 to March 16, 2006, we have drilled four wells (3.4 net to us), three of which were successful and one was a dry hole. We also have one well (0.7 net to us) that is in the process of being drilled.

Producing Well Summary

The following table sets forth the gross and net producing oil and natural gas wells in which we owned an interest at December 31, 2005:

	Oil				Gas
	Gross		Net		Gross		Net
Offshore:
Louisiana		6		4.8		2		1.1
Texas		—		—		2		.8
Federal		28		13.4		29		20.3
Total		34		18.2		33		22.2

We operate 47 of the 67 producing wells presented in the above table. In addition, we own 34 wells, 24.7 net to us, that are shut-in awaiting third party pipelines to return to service, and we also have 10 wells, 9.4 net to us, shut-in awaiting new production facilities. As of December 31, 2005, we owned interests in 17 wells containing multiple completions, which means that a well is producing out of more than one completed zone. Wells with more than one completion are reflected as one well in the table above. If at least one completion is an oil producing zone, then the well is counted as an oil well.

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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 an overriding royalty interest.

	Developed				Undeveloped				Total
	Gross		Net		Gross		Net		Gross		Net
Offshore:
Louisiana		6,085		5,021		2,289		2,289		8,374		7,310
Texas		320		204		—		—		320		204
Federal		196,896		138,294		146,149		146,149		343,045		284,443
Total		203,301		143,519		148,438		148,438		351,739		291,957

143,519 net acres or forty-nine percent of our total acreage is held by production. Our undeveloped leasehold acreage totaling 148,438 net acres expires as follows:

Expires in 2006	10	%
Expires in 2007	7	%
Expires in 2008	31	%
Expires in 2009	33	%
Expires in 2010	19	%
	100	%

Title to our oil and natural gas properties is subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the oil and gas industry, liens incident to operating agreements and for current taxes not yet due and other minor encumbrances. 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 sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. Approximately 43% of our 2005 natural gas sales were priced utilizing index prices and 57% were priced utilizing daily spot prices. Shell Trading (US) Company was our most significant oil purchaser in 2005, accounting for approximately 33% of our total 2005 oil and gas sales. BP Energy Company was our most significant natural gas purchaser in 2005, accounting for approximately 49% of our total 2005 oil and gas 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.

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

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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.

The Outer Continental Shelf Lands Act, or “OCSLA,” which the FERC implements as to transportation and pipeline issues, requires that all pipelines operating on or across the outer continental shelf, or “OCS,” provide open access, non-discriminatory transportation service. One of FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the market to provide producers and shippers on the OCS with greater assurance of open access service on pipelines located on the OCS and to help ensure non-discriminatory rates and conditions of service on such pipelines.

Although the FERC has historically imposed light-handed regulation on offshore facilities that meet its traditional test of gathering status, it has the authority under the OCSLA to exercise jurisdiction over gathering facilities, if necessary, to permit non-discriminatory access to service. In an effort to heighten its oversight of the OCS, the FERC recently attempted to promulgate reporting requirements for all OCS “service providers,” including gatherers, but the regulations were struck down asultra viresby a federal district court, which decision was affirmed by the U.S. Court of Appeals in October 2003. The FERC withdrew those regulations in March 2004. Subsequently, in April 2004, the Minerals Management Service, or “MMS,” initiated an inquiry into whether it should amend its regulations to assure that pipelines provide open and non-discriminatory access over OCS pipeline facilities. For those facilities transporting natural gas across the OCS that are not considered to be gathering facilities, the rates, terms and conditions applicable to this transportation are generally regulated by the FERC under the NGA and NGPA, as well as the OCSLA.

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;

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therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC, Congress and state regulatory authorities will continue.

Federal leases.  Substantially all of our operations are located on federal oil and natural gas leases that are administered by the MMS pursuant to the OCSLA. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed Department of Interior and MMS regulations and orders that are subject to interpretation and change.

For offshore operations, lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plug and abandonment of wells located offshore and the installation and removal of all production facilities.

To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. We are currently exempt from supplemental bonding requirements by the MMS. Under some circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations.

The MMS also administers the collection of royalties under the terms of the OCSLA and the oil and natural gas leases issued thereunder. The amount of royalties due is based upon the terms of the oil and natural gas leases as well as the regulations promulgated by the MMS. The MMS regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases currently rely on arm’s-length sales prices and spot market prices as indicators of value. Although the method of calculating royalties on production from federal leases has been the subject of much public discussion in recent years, the basis for calculating royalty payments established or to be established by the MMS is generally applicable to all federal lessees. Accordingly, we believe that the impact of royalty regulation on our operations should generally be the same as the impact on our competitors.

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 acost-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,

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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

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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 projectsand/or causing us to incur increased operating expenses.

Federal Lease Stipulations address the protection of marine species (sea turtles, marine mammals, Gulf sturgeon and other listed marine species). MMS permit approvals will be conditioned on collection and removal of debris resulting from activities related to exploration, development and production of offshore leases. MMS has issued Notices to Lessees and Operators 2003-G06 advising of requirements for posting of signs in prominent places on all vessels and structures.

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 delayedand/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 CommunityRight-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

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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.

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 have. We face intense competition for the acquisition of oil and natural gas leases and properties. For a more thorough discussion of how competition could impact our ability to successfully complete our business strategy, see “Risk Factors — 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.”

Office and Operations Facilities

Our executive offices are located at 600 Travis Street, Suite 5200, Houston, Texas 77002, and the telephone number is(713) 228-0438. We lease office space in Houston, Texas covering 16,285 square feet at a monthly rate of $28,600. The lease expires on April 30, 2012.

Employees

As of December 31, 2005, we had 20 employees and utilized contract employees for certain of our field operations. We consider our employee relations to be satisfactory.

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Directors, Executive Officers and Other Management

The following table sets forth certain information with respect to our directors and executive officers:

Name	Age		Position
M. Jay Allison		50	Chairman of the Board of Directors
Wayne L. Laufer		60	Chief Executive Officer and Director
Gary W. Blackie		57	President and Director
Roland O. Burns		46	Senior Vice President, Chief Financial Officer, Secretary and Director
John L. Duvieilh		45	Director
D. Michael Harris		59	Director
David K. Lockett		51	Director
Cecil E. Martin, Jr		64	Director
David W. Sledge		49	Director

Executive Officers

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

Mr. Allisonhas been our Chairman of the Board since our formation in July 2004. Mr. Allison has been a director of Comstock Resources, Inc. (“Comstock”) since June 1987, and its President and Chief Executive Officer since 1988. Comstock is our largest stockholder. Mr. Allison was elected Chairman of the Comstock board of directors in 1997. From 1987 to 1988, Mr. Allison served as Comstock’s 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 currently serves on the Board of Regents for Baylor University and on the Advisory Board of the Salvation Army in Dallas, Texas.

Mr. Lauferhas been our Chief Executive Officer since our formation in July 2004 and a director since we converted to a corporation in May 2005. Mr. Laufer co-founded with Mr. Blackie a Gulf of Mexico exploration company in 1984. In 1998, he and Mr. Blackie co-founded Bois d’Arc Offshore Ltd., and Mr. Laufer was a limited partner and its operations engineer, as well as a member of its member-managed general partner, Bois d’Arc Oil & Gas Company, LLC, from 1998 until July 2004. From 1967 to 1983, he was employed by various energy companies. Mr. Laufer received a B.S. degree in civil engineering from Missouri School of Mines & Metallurgy (Rolla) in 1967. Mr. Laufer is a member of the Society of Petroleum Engineers and the Louisiana Independent Oil and Gas Association.

Mr. Blackiehas been our President since our formation in July 2004 and a director since we converted to a corporation in May 2005. Mr. Blackie co-founded with Mr. Laufer a Gulf of Mexico exploration company in 1984. In 1998, he and Mr. Laufer co-founded Bois d’Arc Offshore Ltd., and Mr. Blackie was a limited partner and its exploration geologist, as well as a member of its member-managed general partner, Bois d’Arc Oil & Gas Company, LLC, from 1998 until July 2004. From 1973 to 1983, he was employed by several oil companies. Mr. Blackie received a B.S. degree in geology/civil engineering and a M.S. degree in geology/geophysics from Ohio University in 1971 and 1973, respectively. Mr. Blackie is a member of the American Institute of Petroleum Geologists, Houston Geological Society and Geophysical Society of Houston.

Mr. Burnshas been our Senior Vice President, Chief Financial Officer and Secretary since our formation in July 2004 and a director since we converted to a corporation in May 2005. Mr. Burns has been a director of Comstock since June 1999, and has been Senior Vice President of Comstock since 1994, Chief Financial Officer and Treasurer of Comstock since 1990 and Secretary of Comstock since 1991. Comstock is the indirect parent of Comstock Offshore, which is our largest stockholder. From 1982 to 1989, he was employed by the public accounting firm, Arthur Andersen LLP. During his tenure with Arthur Andersen, 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.

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Outside Directors

Mr. Duvieilhhas been a director since May 2005. Mr. Duvieilh has been associated with the law firm of Jones, Walker, Waechter, Poitevent, Carrère & Denègre, L.L.P. since 1986, and became a partner of such firm in 1992. He received a B.B.A. degree from Loyola University in 1983 and a J.D. degree from Louisiana State University in 1986.

Dr. Harrishas been a director since May 2005. Dr. Harris has been an associate professor of accounting at St. Edwards University since 1998 and has been an independent consultant for a variety of small business owners, providing guidance in the management of information systems, taxation and business planning, since 1990. Dr. Harris received a B.B.A. degree from the University of Texas at Austin in 1970, a M.S. degree in Accountancy from the University of Houston Graduate School of Business in 1971 and a Ph.D. degree from the University of Texas at Austin in 1998 and is a Certified Public Accountant and a Certified Information Technology Professional.

Mr. Locketthas been a director since May 2005. 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 Comstock, a position he has held since July 2001. Mr. Lockett received a B.B.A. degree from Texas A&M University in 1976.

Mr. Martinhas been a director since May 2005. Mr. Martin is an independent commercial real estate developer 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 Comstock, a position he has held since October 1989, 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.

Mr. Sledgehas been a director since May 2005. 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 Comstock, a position he has held since May 1996. He received a B.B.A. degree from Baylor University in 1979.

Available Information

Our executive offices are located at 600 Travis Street, Suite 5200, Houston, TX 77002. Our telephone number is(713) 228-0438. 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 at1-800-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.boisdarcenergy.com) our Annual Report onForm 10-K, Quarterly Reports onForm 10-Q, Current Reports onForm 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we file such material with, or furnish it to, the SEC.

ITEM 1A.   RISK FACTORS

You should carefully consider the following risk factors as well as the other information contained or incorporated by reference in this report, as these important factors, among others, 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.

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Risks Relating to the Oil and Natural Gas Industry and Our Business

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:

•  the domestic and foreign supply of oil and natural gas;

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

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

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

•  domestic government regulation, legislation and policies;

•  the level of global oil and natural gas inventories;

•  weather conditions;

•  technological advances affecting energy consumption;

•  the price and availability of alternative fuels; and

•  overall economic conditions.

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

•  our revenues, profitability and cash flow from operations;

•  the value of our proved oil and natural gas reserves;

•  the economic viability of certain of our drilling prospects;

•  our borrowing capacity; and

•  our ability to obtain additional capital.

We have not entered into crude oil and natural gas price hedging arrangements on any of our anticipated sales. However, we may in the future enter into such arrangements in order to reduce our exposure to price risks. Such arrangements may limit our ability to benefit from increases in oil and natural gas prices.

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. While our overall exploration drilling success rate has been 73%, it can vary widely and may decline in the future. In addition to decreases in our exploration drilling success rate, the actual quantities of reserves that we may discover from exploratory drilling will vary. In 2005, while our exploration activities resulted in additions to our proved reserves of 68 Bcfe, these additions were partially offset by 28 Bcfe of downward revisions to our proved reserve estimates, resulting in a net addition to our proved reserves of 40 Bcfe. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us

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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 prospectsand/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.

We are vulnerable to operational, regulatory and other risks associated with the Gulf of Mexico, including the effects of adverse weather conditions such as hurricanes, because we currently explore and produce exclusively in that area.

Our operations and revenues are significantly impacted by conditions in the Gulf of Mexico because we currently explore and produce almost exclusively in that region. This concentration of activity makes us more vulnerable than many of our competitors to the risks associated with the Gulf of Mexico, including:

•  adverse weather conditions, including hurricanes and tropical storms;

•  delays or decreases in production, the availability of equipment, facilities or services;

•  delays or decreases in the availability of capacity to transport, gather or process production; and

•  changes in the regulatory environment.

Offshore operations are also subject to a variety of operating risks peculiar to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to our facilities and interrupt our production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration and development or result in loss of equipment and property. For example, our operations were substantially impacted in 2004 and 2005 by hurricane and tropical storm activity. In both 2004 and 2005, we had production shut-in for six different hurricanes or tropical storms. In 2004 and 2005 we also had production shut-in awaiting repairs to third party pipelines that were damaged by the hurricanes. As a result of the shut-ins, we were forced to defer production of approximately 2.2 and 4.3 Bcfe in 2004 and 2005, respectively. We also had drilling rigs under contract standing idle for a combined total of 22 and 63 days in 2004 and 2005, respectively. We incurred approximately $1.1 million in 2004 and $4.9 million in 2005 for costs to repair damage to our facilities caused by the hurricanes.

Because all of our operations could experience the same condition at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other operators who have operations in a diversified geographic area.

We need to replace our reserves at a faster rate than companies whose reserves have longer production periods. Our failure to replace our reserves would result in decreasing reserves and production over time.

Unless we conduct successful exploration and development activities or acquire properties containing proven reserves, our proved reserves will decline as reserves are depleted. Producing oil and natural gas reserves are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. High production rates generally result in recovery of a relatively higher percentage of reserves from properties during the initial few years of production. Our current operations are conducted in the Gulf of Mexico. Production from reserves in the Gulf of Mexico generally declines more rapidly than reserves from reservoirs in other producing regions. Our independent petroleum consultants estimate that, on average, 47% of our total proved reserves will be depleted within three years. As a result, our need to replace reserves from new investments is relatively greater than those of producers who produce lower percentages of their reserves over a similar time period, such as those producers who have a portion of their reserves outside of the Gulf of Mexico in areas where the rate of reserve production is lower. If we are not able to find, develop or acquire additional reserves to replace our current and future production, our production rates will decline even if we drill the undeveloped locations that were included in our proved reserves. Our future oil and natural gas reserves and production, and therefore our cash flow and income, are dependent on our success in economically finding or acquiring new reserves and efficiently developing our existing reserves.

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We plan to conduct exploration, development and production operations on the deep shelf of the Gulf of Mexico, which presents greater operating and financial risks than conventional shelf operations.

The deep shelf of the Gulf of Mexico is an area that has had limited historical drilling activity. This is due, in part, to its geological complexity and depth. Deep shelf development can be more expensive than conventional shelf projects as deep shelf development requires more actual drilling days and higher drilling and services costs due to extreme pressure and temperatures associated with greater drilling depths. Moreover, drilling expense and the risk of mechanical failure are significantly higher because of the additional depth and adverse conditions such as high temperature and pressure. For example, our cost to drill a deep shelf exploratory well to a depth of 18,000 feet typically ranges from $12.0 million to $15.0 million while our typical cost to drill conventional shallower shelf wells has been approximately $6.0 million. This additional expense could result in an increased risk of substantial cost overrunsand/or result in uneconomic projects or wells, and requires that a deep shelf drilling prospect have a risk adjusted reserve target of at least 25 Bcfe to meet our economic criteria. Also, seismic interpretation of deeper, geopressured formations is more difficult than at shallower, normally pressured conventional well depths. Our overall exploration success rate has been 73%. Of the 23 deep shelf wells that we have drilled, 12 successfully found hydrocarbons at geologic and drilling depths below 15,000 feet, for a success rate of 52%. This success rate is lower than our overall success rate, reflecting the fact that deep shelf drilling is inherently more risky than conventional shelf drilling. Accordingly, we cannot assure you that our oil and natural gas exploration activities, in the deep shelf and elsewhere, will be commercially successful.

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

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

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

•  recoverable reserves;

•  exploration potential;

•  future oil and natural gas prices;

•  operating costs; and

•  potential environmental and other liabilities.

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

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

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

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

Our business involves a variety of operating risks, including:

•  unusual or unexpected geological formations;

•  fires;

•  explosions;

•  blow-outs and surface cratering;

•  uncontrollable flows of natural gas, oil and formation water;

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

•  pipe, cement, subsea well or pipeline failures;

•  casing collapses;

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

•  abnormally pressured formations; and

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

If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:

•  injury or loss of life;

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

•  pollution and other environmental damage;

•  clean-up responsibilities;

•  regulatory investigation and penalties;

•  suspension of our operations; and

•  repairs to resume operations.

We have limited operating history as a stand-alone entity and might not be able to operate our business or implement our operating strategy successfully.

We were formed in July 2004, and we have a limited operating history. The results of our operations will depend on many factors, including the ones described in this “Risk Factors” section. We also face the risk that we might not successfully implement our operating and business strategies or operate our business as described in this report.

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Our historical financial information may have limited relevance.

The historical financial information included in this report may not reflect what our results of operations, financial position and cash flows would have been had we been formed as an entity during all periods presented or what our results of operations, financial position and cash flows will be in the future. This is because, among other things:

•  our general and administrative expense would have been higher in periods prior to our initial public offering due to increased public company compliance costs, audit and legal expenses and other general and administrative expenses;

•  our interest expense would have been lower due to decreased debt outstanding upon the contribution of $262.5 million of our debt to equity at our formation and by the repayment of borrowings from Comstock Resources, Inc. with the proceeds of our initial public offering; and

•  our income tax expense would have been higher as a result of our being a corporation during all periods.

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 exploration for and development of reserves. Our competitors include companies that have greater financial and personnel resources than we have. We actively compete with other companies in our industry when acquiring new leases or oil and gas properties. For example, new leases acquired from the Minerals Management Services, or MMS, are acquired through a “sealed bid” process and are generally awarded to the highest bidder. Offshore, where exploration is more expensive, our competitors may be better able to withstand sustained periods of unsuccessful drilling. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for oil and natural gas and to acquire additional properties in the future will depend on our ability to profitably conduct operations, to evaluate and select suitable properties and to consummate transactions in this 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.

Our bank credit facility has substantial restrictions and financial covenants, which may reduce our operating flexibility.

We are subject to operational and financial covenants and other restrictions under our bank credit facility. These covenants limit our ability to, among other things:

•  borrow additional money;

•  merge, consolidate or dispose of assets;

•  make certain types of investments;

•  enter into transactions with our affiliates; and

•  pay dividends and distributions.

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These restrictions could limit our ability and the ability of our subsidiaries to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. Our failure to comply with any of these covenants would cause a default under our bank credit facility. 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. Our obligations under the bank credit facility are secured by substantially all of our and our subsidiaries’ assets. An event of default under the bank credit facility will permit the lenders to proceed to directly foreclose on those assets.

Substantial exploration and development activities could require significant outside capital, which could dilute the value of our common stock 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 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 stock. 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 revenues decrease as a result of lower oil or natural gas prices, operating difficulties, hurricane activity, 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 valuesand/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.

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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, approximately 62% of our total proved reserves were developed non-producing and approximately 17% were undeveloped. These reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may ultimately be 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.

Three of our field areas comprise approximately 54% of the PV 10 Value of our total proved reserves. If our reserve estimates in these areas turn out to be inaccurate, there may be a material adverse effect on our financial condition.

Any significant variance from our assumptions regarding future production levels and operating and development costs to actual figures relating to our key field areas could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to this group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Approximately 77% of our total proved reserves in our three key field areas are developed non-producing or undeveloped. To the extent that our reserve estimates in these areas turn out to be inaccurate, the estimated quantities and present value of reserves will most likely vary from our estimates, which in turn would result in a material adverse effect on our financial condition.

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

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

•  the availability and capacity of gathering systems and pipelines;

•  federal and state regulation of production and transportation;

•  changes in supply and demand; and

•  general economic conditions.

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

Our customer base is concentrated and the loss of any of our key customers could therefore adversely affect our financial results.

In 2005, Shell Trading (US) Company and BP Energy Company accounted for approximately 33% and 49%, respectively, of our total sales. To the extent that these and other customers reduce their purchases of oil or natural gas or default on their obligations to us, our results of operations could be adversely affected.

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

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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 have in the past been required to shut-in wells when hurricanes have caused or threatened damage to pipelines and gathering stations. We were forced to defer production of approximately 2.2 and 4.3 Bcfe in 2004 and 2005, respectively, because of hurricane activity and damage to third party pipelines and processing facilities.

We depend on our key management personnel and the loss of either 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 depends on the continued employment of Wayne L. Laufer, our Chief Executive Officer, and Gary W. Blackie, our President. In addition to being our senior management, these individuals lead and are key members of our technical team. Loss of the services of either of these individuals could have a material adverse effect on our operations.

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

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, demand for, and wage rates of, qualified drilling rig crews rise with increases in the number of active rigs in service. If the unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel were particularly severe in the Gulf of Mexico, we could be materially and adversely affected because our operations and properties are concentrated in that area.

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. We were therefore not covered for financial losses incurred as a result of temporarily shutting in our wells during the recent hurricane activity. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Because third party drilling contractors are used to drill our wells, we may not realize the full benefit of workers’ compensation laws in dealing with their employees. In addition, some risks, including pollution and environmental risks, generally are not fully insurable.

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

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

•  lease permit restrictions;

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

•  spacing of wells;

•  unitization and pooling of properties;

•  safety precautions;

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•  regulatory requirements; and

•  taxation.

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

•  personal injuries;

•  property and natural resource damages;

•  well reclamation costs; and

•  governmental sanctions, such as fines and penalties.

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

Compliance with MMS regulations could significantly delay or curtail our operations or require us to make material expenditures, all of which could have a material adverse effect on our financial condition or results of operations.

Substantially all of our operations are located on federal oil and natural gas leases that are administered by the MMS. As an offshore operator, we must obtain MMS approval for our exploration, development and production plans prior to commencing such operations. The MMS has promulgated regulations that, among other things, require us to meet stringent engineering and construction specifications, restrict the flaring or venting of natural gas, govern the plug and abandonment of wells located offshore and the installation and removal of all production facilities, and govern the calculation of royalties and the valuation of crude oil produced from federal leases.

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

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

•  require the acquisition of a permit before drilling commences;

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

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

•  impose substantial liabilities for pollution resulting from our operations.

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

•  the assessment of administrative, civil and criminal penalties;

•  the incurrence of investigatory or remedial obligations; and

•  the imposition of injunctive relief.

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.

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

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

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

•  a classified board of directors;

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

•  requiring advance notice procedures with respect to stockholder proposals and director nominations;

•  requiring removal of directors by a supermajority stockholder vote;

•  prohibiting cumulative voting in the election of directors; and

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

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

Risks Related to Our Relationship With Comstock

As long as Comstock owns a substantial amount of our outstanding common stock, Comstock will have significant influence over matters to be submitted to our stockholders for approval. This ownership may adversely affect the value of our common stock and inhibit potential changes of control.

Comstock owns 29,935,761 shares of our common stock, representing approximately 48% of our voting interests. Therefore, Comstock has the ability to exert significant influence over the outcome of all matters requiring stockholder approval, including:

•  the composition of our board of directors and, through it, any determination with respect to our business direction and policies, including the appointment and removal of officers;

•  incentive compensation, which may affect our ability to retain key employees;

•  mergers or other business combinations;

•  our acquisition or disposition of assets;

•  a takeover by a third party;

•  our financing decisions and capital raising activities;

•  payment of dividends on our common stock; and

•  amendments to our articles of incorporation or bylaws.

Comstock is not prohibited from selling its interest in us to a third party. In addition, its concentrated influence could discourage others from initiating any potential merger, takeover or other change of control transaction that might be beneficial to our business. As a result, the market price of our common stock could be adversely affected.

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Certain of our executive officers and directors face conflicts of interest relating to the positions they hold with other entities, which could be resolved in a manner adverse to us and harm our business.

Two of our executive officers and five of our nine directors are also executive officers or directors of Comstock. These persons owe fiduciary duties to Comstock and its stockholders and these duties may from time to time conflict with the fiduciary duties such individuals owe to us and our stockholders. For example, conflicts of interest could arise in decisions or activities related to:

•  the allocation of new investments between us and Comstock;

•  the allocation of time and resources between us and Comstock;

•  financing decisions made by us and Comstock; and

•  the terms of the services agreement with Comstock.

All of the conflicts of interest discussed above may also be impacted by the fact that some of such individuals own a significant amount of Comstock’s common stock or may have a compensation structure tied to the performance of Comstock and this ownership or compensation structure may potentially provide for greater remuneration in the event a business opportunity is presented to Comstock rather than us. We do not have a conflicts of interest policy. We expect conflicts to be resolved on acase-by-case basis, and in a manner consistent with applicable law. For example, if a business opportunity were presented to both us and Comstock for consideration, directors affiliated with Comstock would not participate in our consideration of that opportunity. However, these conflicts could be resolved in a manner that could harm our business.

Comstock is not prohibited from competing with us, which could adversely affect our ability to succeed.

Comstock is an independent energy company engaged in the acquisition, development, production and exploration of oil and natural gas properties. Comstock is not prohibited from separately engaging in the exploration and production of natural gas and oil in the Gulf of Mexico shelf region and may engage in such activities in the future. In addition, we could expand the focus of our currently planned activities and enter into businesses and regions that compete with Comstock. Since two of our executive officers and five of our nine directors are also executive officers and directors of Comstock, a conflict could arise with respect to activities that compete with Comstock and such conflict may be resolved in a manner that is adverse to us.

ITEM 1B.   UNRESOLVED STAFF COMMENTS

None.

ITEM 3.   LEGAL PROCEEDINGS

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

ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

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

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PART II

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

Our common stock is listed for trading on the New York Stock Exchange under the symbol “BDE” and began trading on May 6, 2005 following our initial public offering. The following table sets forth, on a per share basis for the periods indicated, the high and low sales prices by calendar quarter for the periods indicated as reported by the New York Stock Exchange.

		High		Low
2005 —	First Quarter	$	—	$	—
	Second Quarter(1)		15.61		11.50
	Third Quarter		17.66		13.40
	Fourth Quarter		18.00		13.58

(1) May 6, 2005 to June 30, 2005.

As of March 16, 2006, we had 64,145,000 shares of common stock outstanding, which were held by 62 holders of record and approximately 5,600 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 from paying or declaring cash dividends.

The net proceeds from our initial public offering in May 2005 were used to repay our indebtedness to Comstock.

The following table summarizes the options that have been awarded under our incentive plan and that were outstanding at December 31, 2005:

		Number of options				Weighted average
		granted and		Weighted average		remaining life		Number of options
Exercise price		outstanding		exercise price		(years)		exercisable
$	6.00 — $15.55		3,105,000	$	6.84		8.6		560,000

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ITEM 6.   SELECTED FINANCIAL DATA

The following tables set forth selected historical financial data as of and for each of the years in the five-year period ended December 31, 2005. The selected historical combined financial data as of and for the years ended December 31, 2001, 2002 and 2003 and the period from January 1, 2004 to July 15, 2004 is derived from our predecessors’ audited combined financial statements. The consolidated financial data for the period from our inception (July 16, 2004) to December 31, 2004 and for the year ended December 31, 2005 is derived from our audited financial statements. The data presented below should be read in conjunction with our consolidated financial statements and our predecessors’ combined financial statements and the notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Statement of Operations Data:

	Combined Bois d’Arc Energy Predecessors												Bois d’Arc Energy
										Period			Period from
										from			Inception
										January 1,			(July 16,			Year
										2004 to			2004) to			Ended
	Year Ended December 31,									July 15,			December 31,			December 31,
	2001			2002			2003			2004			2004			2005
	(Amounts in thousands except per share data)
Oil and gas sales	$	96,695		$	76,067		$	133,450		$	70,341		$	72,721		$	184,436
Operating expenses:
Oil and gas operating(1)		15,151			14,725			22,290			15,233			16,602			37,089
Exploration		10,782			5,458			800			2,676			12,040			16,794
Depreciation, depletion and amortization		34,535			32,490			44,285			22,831			21,761			42,854
Impairment		2,850			—			500			—			—			590
General and administrative, net		2,788			2,600			3,481			1,450			2,641			9,331
Total operating expenses		66,106			55,273			71,356			42,190			53,044			106,658
Income from operations		30,589			20,794			62,094			28,151			19,677			77,778
Other income (expenses):
Interest income		479			81			154			75			74			222
Interest expense		(14,855	)		(10,818	)		(9,580	)		(4,453	)		(2,665	)		(3,775	)
Formation costs		—			—			—			—			(1,838	)		—
Loss on disposal of assets		—			—			—			—			—			(89	)
Income before income taxes		16,213			10,057			52,668			23,773			15,248			74,136
Provision for income taxes		—			—			—			—			—			(125,808	)
Net income before cumulative effect of change in accounting principle		16,213			10,057			52,668			23,773			15,248			(51,672	)
Cumulative effect of change in accounting principle		—			—			(739	)		—			—			—
Net income	$	16,213		$	10,057		$	51,929		$	23,773		$	15,248		$	(51,672	)
Income (loss) per share (unit):
Basic													$	0.30		$	(0.89	)
Diluted													$	0.30		$	(0.89	)
Weighted average common and common stock equivalent shares (units) outstanding:
Basic														50,000			57,909
Diluted(2)														50,485			57,909
Pro forma computation related to conversion to a corporation for income tax purposes:
Income before income taxes	$	16,213		$	10,057		$	52,668		$	23,773		$	15,248		$	74,136
Pro forma provision for income taxes		(5,675	)		(3,520	)		(18,434	)		(8,321	)		(5,807	)		(26,914	)
Pro forma net income	$	10,538		$	6,537		$	34,234		$	15,452		$	9,441		$	47,222
Pro forma income (loss) per share (unit):
Basic													$	0.19		$	0.82
Diluted													$	0.19		$	0.79
Weighted average common and common stock equivalent shares (units) outstanding:
Basic														50,000			57,909
Diluted														50,485			59,655

(1)	Includes lease operating costs and production and ad valorem taxes.
(2)	Diluted same as basic in 2005 due to the loss.

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Balance Sheet Data:

	Combined Bois d’Arc Energy Predecessors						Bois d’Arc Energy
	As of December 31,						As of December 31,
	2001		2002		2003		2004		2005
	(In thousands)
Cash and cash equivalents	$	7,044	$	12,311	$	22,019	$	2,416	$	12,043
Property and equipment, net		305,401		348,004		413,412		511,477		661,931
Total assets		324,394		377,170		461,693		530,583		712,902
Bank debt		12,500		14,000		10,500		—		69,000
Payable to Comstock Resources(1)		273,681		299,864		311,706		148,066		—
Stockholders’ equity		9,683		19,132		64,949		319,485		419,206

(1) Payable to Comstock Resources of our predecessors represents advances made to Comstock Offshore by Comstock to fund Comstock Offshore’s acquisition, development and exploration activities. Interest expense has been included in the combined financial statements on the advances made to Comstock Offshore based on Comstock’s average interest costs under its bank credit facility. Payable to Comstock Resources of Bois d’Arc Energy, LLC represents advances made to us by Comstock in connection with our formation.

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

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

Overview

Our Business.  We were formed in July 2004. We are a growing independent exploration company engaged in the discovery and production of oil and natural gas in the outer continental shelf of the Gulf of Mexico. As of December 31, 2005, we owned interests in 67 (40.4 net to us) producing oil and natural gas wells in the federal and state waters of the Gulf of Mexico. In addition, we had another 34 wells shut-in waiting on third party pipelines to return to service and 10 wells awaiting the installation of production facilities. We operate 91 of the 111 wells that we own. In managing our business, we are concerned primarily with maximizing return on our stockholders’ equity. To accomplish this primary goal, we focus on profitably increasing our oil and natural gas reserves. See “Risk Factors” for a description of risks inherent in the oil and natural gas industry and our business, any one of which, if it occurs, can negatively impact our ability to accomplish our primary goal.

Our future growth will be driven primarily by exploration activities. We have 43 identified exploration prospects in our inventory that are located on our leasehold acreage and supported by3-D seismic. We believe that by adhering to our prospect selection methodology, we have realized high historical exploration success rates. We believe that our inventory, including development wells resulting from new discoveries, will provide us with opportunities to increase our reserves over the next three to five years. Under our current drilling budget, we plan to drill approximately eight of these prospects in 2006. However, the actual number of prospects that we drill over any defined time period will be determined based upon the number of rig days that we have available under our contracts with drilling contractors and the amount of time it takes to drill each prospect selected by our management and technical team. We use the successful efforts method of accounting which allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration activities. Accordingly, our exploration costs consist of costs we incur to acquire and reprocess3-D seismic data, impairments of our unevaluated leasehold where we were not successful in discovering reserves and the costs of unsuccessful exploratory wells that we drill.

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We generally sell our oil and natural gas at current market prices at the point our platforms connect to third party purchaser pipelines. We market our products several different ways depending upon a number of factors, including the availability of purchasers for the product, the availability and cost of pipelines near the related production platform, market prices, pipeline constraints and operational flexibility. Accordingly, our revenues are heavily dependent upon the prices of, and demand for, oil and natural gas. Oil and natural gas prices have historically been volatile and are likely to remain volatile in the future. Our revenues for 2003, 2004 and 2005 benefited from a general increase in oil and natural gas prices. We have not entered into oil and natural gas hedging arrangements on any of our anticipated sales. However, we may in the future enter into such arrangements in order to reduce our exposure to price risks. Such arrangements may also limit our ability to benefit from increases in oil and natural gas prices.

Our operating costs include the expense of operating our wells, platforms and other infrastructure in the Gulf of Mexico and transporting our products to the point of sale. Our operating costs are generally comprised of several components, including costs of field personnel, repair and maintenance cost, production supplies, fuel used in operations, transportation cost, workover cost and production and ad valorem taxes for properties located in state waters.

Like all oil and natural gas exploration and production companies, we face the challenge of replacing our reserves. Oil and natural gas properties in the Gulf of Mexico typically deplete at higher rates than do properties in other areas of the United States. Although in the past we have offset the effect of sharply declining production rates from existing properties through successful drilling efforts, there can be no assurance that we will be able to offset production declines or maintain production at our current rates through additional discoveries. We intend to continue our focus on adding reserves through drilling efforts, and our future growth will depend on our ability to continue to add new reserves in excess of production.

Our exploration and production activities are conducted in the Gulf of Mexico. Our operations are significantly impacted by conditions in the Gulf of Mexico, such as adverse weather conditions; the availability of equipment, facilities or services; delays and decreases in the availability of capacity to transport, gather or process production; and changes in the regulatory environment. We maintain insurance to mitigate the risk of damage to our production facilities that could result from adverse weather conditions. We have periodically shut-in our production as a result of hurricanes or tropical storm activity. As a result of the hurricane activity, we deferred production of approximately 2.2 Bcfe in 2004 and 4.3 Bcfe in 2005. We also had drilling rigs under contract standing idle during the storm activity for a combined total of 22 and 63 days in 2004 and 2005, respectively. We incurred approximately $1.1 million and $4.9 million in costs to repair damage to our facilities caused by the hurricane activity in 2004 and 2005, respectively.

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 operational 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. Applicable environmental regulations require us to remove our platforms after production has ceased, to plug and abandon our wells and to remediate any environmental damage our operations may have caused. The present value of the estimated future costs to plug and abandon our oil and gas wells and to dismantle and remove our production facilities is included in our reserve for future abandonment costs, which was $35.0 million as of December 31, 2005.

Our Predecessors.  In December 1997, Comstock Offshore, LLC, an indirect wholly-owned subsidiary of Comstock, acquired from Bois d’Arc Resources and other interest owners certain offshore oil and natural gas properties, including the properties we now own at Ship Shoal blocks 66, 67, 68 and 69 and South Pelto block 1. Bois d’Arc Resources was the predecessor to Bois d’Arc Resources, Ltd., an entity owned by two of our executive officers, directors and stockholders, Gary W. Blackie and Wayne L. Laufer. In connection with this acquisition, Comstock Offshore, Bois d’Arc Resources, Ltd. and Bois d’Arc Offshore, Ltd., another entity owned by Messrs. Blackie and Laufer, established a joint venture to explore for oil and natural gas in the Gulf of Mexico. Under the joint exploration venture, Bois d’Arc was responsible for developing a budget for exploration activities and for generating exploration prospects in the Gulf of Mexico utilizing3-D seismic data and their extensive geological expertise in the region. Comstock Offshore had to approve the budget and would advance the funds for

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the acquisition of3-D seismic data and leases needed to conduct exploration activities. Comstock Offshore was reimbursed for all advanced costs and was entitled to a non-promoted working interest in each prospect generated. For each successful discovery well drilled pursuant to the joint exploration venture, Comstock issued to the two principals of Bois d’Arc warrants exercisable for the purchase of shares of Comstock’s common stock. Successful wells drilled under the exploration venture were operated by Bois d’Arc Offshore, Ltd. pursuant to a joint operating agreement entered into by the parties participating in the prospect, including Comstock Offshore and the Bois d’Arc Participants. Any future operation on the lease including drilling additional wells on the acreage associated with the prospect was conducted under the joint operating agreement and had to be approved by the participating parties.

Our Formation.  In July 2004, Comstock, Bois d’Arc Resources, Ltd. and Messrs. Blackie and Laufer formed our company to replace the joint exploration venture. Bois d’Arc Resources, Ltd., Bois d’Arc Offshore, Ltd., and the other entities owned by Messrs. Blackie and Laufer and who we collectively refer to as “Bois d’Arc,” and certain participants in their exploration activities, who we collectively refer to as the “Bois d’Arc Participants,” and Comstock Offshore contributed to Bois d’Arc Energy, LLC substantially all of their Gulf of Mexico properties (which properties are identified in “Properties — Primary Operating Areas”) and assigned to Bois d’Arc Energy, LLC their related liabilities, including certain debt, in exchange for equity interests in Bois d’Arc Energy, LLC. The equity interests issued in exchange for the contributions were determined by using a valuation of the properties contributed by the particular contributors conducted by Lee Keeling and Associates, Inc., independent petroleum consultants, relative to the value of the properties contributed by all contributors. Comstock Offshore contributed its Gulf of Mexico properties and assigned $83.2 million of related debt in exchange for an approximately 60% ownership interest. Each of the Bois d’Arc Participants contributed its interest in commonly owned Gulf of Mexico properties and they assigned in the aggregate $28.2 million of related liabilities in exchange for an approximately 40% aggregate ownership interest. The Bois d’Arc Participants also received $27.6 million in cash to equalize the amount that Comstock Offshore’s debt exceeded its proportional share of the liabilities assigned. Of such amount, $2.7 million was paid to Mr. Blackie or entities controlled by him, $10.5 million was paid to Mr. Laufer or entities controlled by him, $2.0 million was paid to D. Michael Harris, one of our outside directors, and $0.2 million was paid to John L. Duvieilh, another one of our outside directors. We also reimbursed Comstock Offshore $12.7 million and Bois d’Arc $0.8 million for advances made under the joint exploration venture for undrilled prospects.

Comparability of Results

The combined financial statements included in this report and the discussion below with respect to periods prior to July 16, 2004 are based on the financial condition and results of operations of Comstock Offshore and the Bois d’Arc Participants as they relate to the properties contributed to us on a combined basis. Our predecessors, the Bois d’Arc Participants and Comstock Offshore, operated as joint venture partners from 1997 until our formation in July 2004. Bois d’Arc Energy, LLC (prior to its conversion to a corporation) was a continuation of this joint venture and formalized the relationship of the predecessors. A majority of the interests of our predecessors were in the same properties and the operations were under the combined management of the predecessors. As such, combined financial statements using historical cost basis properly reflect the historical combined operations of Comstock Offshore and the Bois d’Arc Participants. In connection with our initial public offering in May 2005, we converted from a limited liability company to a corporation.

The general and administrative expenses included in our predecessors’ combined financial statements reflect the general and administrative expenses of Bois d’Arc, a privately-held company, and certain general and administrative expenses allocated to Comstock Offshore by its parent, Comstock. As such, our general and administrative expenses are significantly different than those of our predecessors.

Our predecessors were either individuals or partnerships or limited liability companies that passed through their taxable income to their owners. Accordingly, no provision for federal or state corporate income taxes was made in our predecessors’ combined financial statements. As a result of our conversion to a corporation, our earnings are now subject to federal, state and local taxes at a combined rate of approximately 36%.

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Results of Operations

Our operating data for the year ended December 31, 2003, the period from January 1, 2004 to July 15, 2004, the period from our inception on July 16, 2004 to December 31, 2004 and for the year ended December 31, 2005 is summarized below:

					Bois d’Arc
	Combined Bois d’Arc Energy				Energy
	Predecessors				Period from
			Period from		Inception				Bois d’Arc
			January 1,		(July 16,		Combined		Energy
	Year Ended		2004 to		2004) to		Year Ended		Year Ended
	December 31,		July 15,		December 31,		December 31,		December 31,
	2003		2004		2004		2004		2005
	(In thousands, except per unit amounts)
Revenues:
Oil and gas sales	$	133,450	$	70,341	$	72,721	$	143,062	$	184,436
Expenses:
Oil and gas operating(1)	$	22,290	$	15,233	$	16,602	$	31,835	$	37,089
Exploration	$	800	$	2,676	$	12,040	$	14,716	$	16,794
Depreciation, depletion and amortization	$	44,285	$	22,831	$	21,761	$	44,592	$	42,854
Net Production Data:
Oil (MBbls)		1,461		832		779		1,611		1,155
Natural gas (MMcf)		15,231		6,267		5,908		12,175		14,896
Natural gas equivalent (MMcfe)		23,994		11,260		10,578		21,838		21,825
Average Sales Price:
Oil ($/Bbl)	$	31.03	$	36.50	$	44.45	$	40.36	$	52.88
Natural gas ($/Mcf)	$	5.79	$	6.38	$	6.45	$	6.41	$	8.28
Average equivalent price ($/Mcfe)	$	5.56	$	6.25	$	6.87	$	6.55	$	8.45
Expenses ($ per Mcfe):
Oil and gas operating(1)	$	0.93	$	1.35	$	1.57	$	1.46	$	1.70
Depreciation, depletion and amortization(2)	$	1.84	$	2.02	$	2.04	$	2.04	$	1.95

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

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Oil and gas sales.  Our oil and gas sales in 2005 increased $41.3 million (29%) to $184.4 million from $143.1 million for 2004. The increase in sales was attributable to higher oil and gas prices we realized in 2005. Our average gas price increased 29% and our average oil price increased 31% in 2005 as compared to average prices in 2004. We had 4.3 Bcfe of production deferred in 2005 because of the hurricane activity. Our natural gas production increased 22% and our oil production decreased 28% from 2004. After taking into account the deferred production resulting from the hurricanes, our natural gas production gains related primarily to new wells drilled at Vermillion blocks 51 and 122 and Ship Shoal blocks 109 and 110. The oil production decline was primarily attributable to our Ship Shoal 113 Unit.

Oil and gas operating expenses.  Our oil and gas operating costs for 2005 increased $5.3 million (17%) to $37.1 million from $31.8 million in 2004. Oil and gas operating expenses per equivalent Mcf produced increased

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$0.24 to $1.70 in 2005 from $1.46 in 2004. The increase in operating expenses in 2005 primarily is related to hurricane repair costs, operating costs of new wells put on production in 2005 as well as higher lifting costs per equivalent Mcf produced due to the deferred production related to hurricane activity. Including the deferred production and excluding the repair cost of $4.9 million we expensed in 2005, our operating costs per Mcfe would have been $1.23 per Mcfe in 2005.

Impairment.  We recorded an impairment to our oil and gas properties of $0.6 million in 2005 related to a minor valued field where an impairment was indicated based on estimated future cash flows attributable to the field’s estimated proved oil and natural gas reserves.

Exploration expense.  We incurred $16.8 million in exploration expense in 2005 which primarily related to the costs associated with drilling one exploratory dry hole and the acquisition and reprocessing of3-D seismic data. In 2004, our exploration expense of $14.7 million included the cost of five unsuccessful exploratory wells drilled and the acquisition and reprocessing of3-D seismic data.

Depreciation, depletion and amortization.  Our depreciation, depletion and amortization expense decreased $1.7 million (4%) to $42.9 million from $44.6 million in 2004. Depreciation, depletion and amortization expense per equivalent Mcf produced of $1.95 in 2005 decreased $0.09 (4%) as compared to $2.04 for 2004. This decrease in the amortization rate primarily reflects reserve additions from successful exploratory wells drilled in 2005.

General and administrative expenses.  Our general and administrative expenses, which are reported net of operating fees that we receive, were $9.3 million in 2005. During 2004 our general and administrative expenses were $1.5 million for the period from January 1, 2004 to July 15, 2004 and $2.6 million for the period from our inception on July 16, 2004 to December 31, 2004. These costs have increased primarily as a result of the management and staff that we hired after our formation as well as compliance costs associated with being a public company in 2005. Included in general and administrative expenses are stock-based compensation of $5.6 million in 2005 and $2.5 million for the period from our inception through December 31, 2004.

Interest expense.  Interest expense for 2005 was $3.8 million. Interest expense for the period from January 1, 2004 to July 15, 2004 was $4.5 million and for the period from our inception to December 31, 2004 was $2.7 million. Interest expense decreased in 2004 primarily due to a reduction in borrowings outstanding. Average borrowings of $74.1 million during 2005 was lower than the $242.8 million average borrowings outstanding in 2004. The decrease due to the lower debt balances was partially offset by an increase in our average interest rate, which increased to 4.8% in 2005 from 3.0% in 2004.

Income taxes.  Upon our conversion from a limited liability company to a corporation on May 10, 2005, we began to reflect a provision for income taxes for income subsequent to our conversion at an average tax rate of 36%. The provision for the period from May 11, 2005 to December 31, 2005 was $17.6 million. In connection with our conversion to a corporation, we recorded a one time provision of $108.2 million to reflect our deferred tax liability on the date of conversion. No income taxes were reflected for any period prior to the conversion as our taxable income was passed through to our members.

Net income.  We reported a net loss of $51.7 million ($0.89 per share) in 2005 as compared to net income of $23.8 million for the period from January 1, 2004 to July 15, 2004 and $15.2 million for the period from our inception on July 16, 2004 to December 31, 2004. The net loss in 2005 resulted from the $108.2 million provision for the deferred tax liability upon our conversion to a corporation. Without the one time provision, we would have reported net income of $56.5 million ($0.95 per share) in 2005.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

Oil and gas sales.  Our oil and gas sales increased $9.6 million, or 7%, in 2004 to $143.1 million from $133.5 million in 2003. The increase in sales resulted from the 18% higher oil and gas prices that we realized in 2004, partially offset by a 9% decrease in our production. Our average realized gas price increased by 11% and our average realized oil price increased by 30% in 2004 as compared with the average prices we realized in 2003. On an equivalent unit basis, the average price received for our production in 2004 was $6.55 per Mcfe, which was 18% higher than our average price received in 2003 of $5.56 per Mcfe. Our natural gas production decreased by 20% while our oil production increased by 10%. The natural gas production decrease was primarily related to declines

37

from our wells at South Pelto block 5, South Timbalier blocks 34 and 50 and Ship Shoal block 146. These declines were partially offset by new production from the Ship Shoal 113 unit, South Timbalier block 30 and South Pelto block 22. The oil production increase related to production resulting from our acquisition of the additional interests in the Ship Shoal 113 unit in late 2003, and new wells drilled at South Timbalier block 30 and South Pelto blocks 22 and 25. The new oil production was partially offset by declines at Ship Shoal blocks 66, 67, 68 and 69, South Pelto block 5 and South Timbalier blocks 34 and 50. In addition, our production in 2004 was impacted by hurricane activity which caused us to defer production of approximately 2.2 Bcfe in 2004.

Oil and gas operating expenses.  Our oil and gas operating expenses, including production taxes, increased $9.5 million, or 43%, to $31.8 million in 2004 from $22.3 million in 2003. Our operating expenses per equivalent Mcf produced increased $0.53, or 57%, to $1.46 for 2004 from $0.93 for 2003. The increase in operating expenses was primarily related to higher lifting costs associated with the Ship Shoal 113 unit in which we acquired an additional interest in late 2003 and higher insurance costs. In addition, our oil and gas operating expenses in 2004 included $1.1 million in costs to repair damage resulting from the hurricane activity.

Exploration expense.  In 2004, we incurred $14.7 million in exploration expense, which related to the cost of five unsuccessful exploratory wells drilled and the acquisition and reprocessing of3-D seismic data. In 2003, our exploration expense was $0.8 million, which related to the acquisition of3-D seismic data. We did not drill any unsuccessful exploratory wells in 2003.

Depreciation, depletion and amortization.  Our depreciation, depletion and amortization expense increased $0.3 million, or 1%, to $44.6 million in 2004 from $44.3 million in 2003. Our depreciation, depletion and amortization expense per equivalent Mcf produced increased by $0.20, or 11%, to $2.04 for 2004 as compared to $1.84 for 2003. The increase in the amortization rate was attributable to an increase in production in 2004 from properties with higher capitalized costs.

General and administrative expenses.  Our general and administrative expenses, which are reported net of operating fees that we receive, were $2.6 million for the period from our inception on July 16, 2004 to December 31, 2004 and $1.5 million for the period from January 1, 2004 to July 15, 2004. In 2003, our general and administrative expenses were $3.5 million. The increase in the period from our inception to December 31, 2004 related primarily to $2.5 million in equity-based compensation expense included in our general and administrative expenses for awards made to employees under our long-term incentive plan.

Interest expense.  Our interest expense for the period from our inception on July 16, 2004 to December 31, 2004 was $2.7 million and $4.5 million for the period from January 1, 2004 to July 15, 2004. In 2003, our interest expense was $9.6 million. The decreases were due to a decrease in our outstanding borrowings from Comstock offset partially by increases in our average interest rates. Average outstanding borrowings from Comstock were $149.5 million during the period from our inception to December 31, 2004 and $325.8 million for the period from January 1, 2004 to July 15, 2004 as compared to $299.4 million for the year ended December 31, 2003. The average interest rate on borrowings from Comstock was 3.8% during the period from our inception to December 31, 2004 and 2.6% for the period from January 1, 2004 to July 15, 2004 as compared to 3.0% for the year ended December 31, 2003.

Net income.  We reported net income of $15.2 million for the period from our inception on July 16, 2004 to December 31, 2004 and $23.8 million for the period from January 1, 2004 to July 15, 2004 as compared to $51.9 million in 2003. Net income in 2003 included a loss of $0.7 million relating to the cumulative effect of a change in our accounting for future abandonment cost of our oil and gas properties. Net income in the period from our inception to December 31, 2004 included a charge of $1.8 million for costs incurred in connection with our formation. The lower net income amounts in the 2004 periods were primarily due to our higher operating and exploration expenses in these periods.

Liquidity and Capital Resources

Funding for our activities has historically been provided by net cash flow from operating activities or from borrowings. In 2005 our primary sources of funds were $145.1 million from our initial public offering, $69.0 million borrowed under our bank credit facility and $135.4 million in net cash flow from operating activities. For the period

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from our inception on July 16, 2004 through December 31, 2004, our primary sources of funds were net cash flow from operating activities of $49.5 million and borrowings of $64.9 million from Comstock that we incurred in connection with our formation. For the period from January 1, 2004 to July 15, 2004 our primary sources of funds were $51.0 million of cash flow from operating activities and $31.6 million of borrowings from Comstock Resources.

Our need for capital, in addition to funding our ongoing operations, primarily relates to our exploration for oil and natural gas reserves, the development and acquisition of our oil and gas properties and the repayment of our debt. In 2005 we incurred $189.8 million in capital expenditures for exploration, development and acquisition activities. For the period from our formation on July 16, 2004 through December 31, 2004, we incurred capital expenditures of $59.7 million for exploration, development and acquisition activities. We also paid certain of our contributors $41.1 million in connection with our formation in July 2004 and retired $28.2 million of our debt. For the period from January 1, 2004 to July 15, 2004 we incurred capital expenditures of $83.3 million and repaid $1.9 million of outstanding debt.

Our capital expenditure activity is summarized in the following table:

					Bois d’Arc
	Combined Bois d’Arc Energy				Energy
	Predecessors				Period from
			Period from		Inception				Bois d’Arc
			January 1,		(July 16,		Combined		Energy
	Year Ended		2004 to		2004) to		Year Ended		Year Ended
	December 31,		July 15,		December 31,		December 31,		December 31,
	2003		2004		2004		2004		2005
	(In thousands)
Acquisitions of proved oil and gas properties	$	4,613	$	715	$	—	$	715	$	—
Acquisitions of unproved oil and gas properties		1,438		2,049		120		2,169		4,968
Exploration and development expenditures(1)		92,792		80,509		59,003		139,512		182,594
Other		131		—		580		580		2,209
Total	$	98,974	$	83,273	$	59,703	$	142,976	$	189,771

(1) Excludes geological and geophysical expenses which are not capitalized.

The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. We have budgeted approximately $180.0 million for development and exploration projects in 2006. We expect to use internally generated cash flow from operating activities to fund our development and exploration activities. Our operating cash flow is highly dependent on oil and natural gas prices.

The hurricane activity in 2005 caused us to defer 4.3 Bcfe of production. As a result of the deferred production and the resultant decrease in our oil and gas sales, we borrowed $58.0 million under our bank credit facility during the third and fourth quarters of 2005 to fund a portion of our drilling expenditures.

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The following table summarizes our aggregate liabilities and commitments as of December 31, 2005 by year of maturity:

	2006		2007		2008		2009		2010		Thereafter		Total
	(In thousands)
Bank credit facility	$	—	$	—	$	—	$	69,000	$	—	$	—	$	69,000
Interest on debt obligations		3,892		3,892		3,892		1,396		—		—		13,072
Operating leases		377		383		388		402		412		560		2,522
Contracted drilling services		32,974		—		—		—		—		—		32,974
Acquisition of seismic data		3,867		—		—		—		—		—		3,867
	$	41,110	$	4,275	$	4,280	$	70,798	$	412	$	560	$	121,435

On May 11, 2005 we completed an initial public offering of 13.5 million shares of common stock at $13.00 per share to the public. We sold 12.0 million shares of common stock and received proceeds of $145.1 million and a selling stockholder sold 1.5 million shares, of which we received no proceeds. Prior to completing the offering, we converted from a limited liability company to a corporation and changed our name to Bois d’Arc Energy, Inc.

In connection with our initial public offering, we entered into a $175.0 million bank credit facility with The Bank of Nova Scotia and several other banks. Borrowings under the credit facility are limited to a borrowing base that is re-determined semi-annually based on the banks’ estimates of the future net cash flows of our oil and natural gas properties. The borrowing base was $100.0 million as of December 31, 2005. The determination of the borrowing base is at the sole discretion of the administrative agent and the bank group. The credit facility matures on May 11, 2009. Borrowings under the credit facility bear interest at the Company’s option at either (1) LIBOR plus a margin that varies from 1.25% to 2.0% depending upon the ratio of the amounts outstanding to the borrowing base or (2) the base rate (which is the higher of the prime rate or the federal funds rate) plus a margin that varies from 0% to 0.75% depending upon the ratio of the amounts outstanding to the borrowing base. A commitment fee ranging from 0.375% to 0.50% (depending upon the ratio of the amounts outstanding to the borrowing base) is payable on the unused borrowing base.

Indebtedness under the credit facility is secured by substantially all of our and our subsidiaries’ assets, and all of our subsidiaries are guarantors of the indebtedness. The credit facility contains covenants that restrict the payment of cash dividends, borrowings, sales of assets, loans to others, capital expenditures, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders and requires us to maintain a ratio of current assets, including the availability under the bank credit facility, to current liabilities of at leastone-to-one and a ratio of indebtedness to earnings before interest, taxes, depreciation, depletion, and amortization, exploration and impairment expense of no more than 2.5 to one.

In connection with our formation, Comstock provided a revolving line of credit to us with a maximum outstanding amount of $200.0 million. Approximately $152.4 million of this revolver was used to repay the debt assigned to us in our formation, including the $83.2 million payable to Comstock, $13.5 million of advances made by Comstock Offshore and Bois d’Arc under the joint exploration venture and $55.7 million to refinance the bank loan and other obligations of the Bois d’Arc Participants. Borrowings under this credit facility bore interest at our option at either LIBOR plus 2% or the base rate (which is the higher of the prime rate or the federal funds rate) plus 0.75%. All of our borrowings under this credit facility were repaid in full with proceeds from our initial public offering and borrowings under our new bank credit facility, and this credit facility was cancelled in May 2005.

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

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Critical Accounting Policies

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

With respect to periods prior to July 16, 2004 (the date of our formation), the discussion contained herein of our financial condition and results of operations is based upon the information reported in our predecessors’ combined financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States, or GAAP. In many cases, the accounting treatment of particular transactions is specifically required by GAAP. The preparation of our financial statements requires us to make estimates and use assumptions that can affect the reported amounts of assets, liabilities, revenues or expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates. Our significant accounting policies are detailed in Note 2 to our combined and consolidated financial statements. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment or estimates by our management.

Presentation of combined financial statements.  Our predecessors, the Bois d’Arc Participants and Comstock Offshore, operated as joint venture partners from 1997 until our formation in 2004. Bois d’Arc Energy, LLC was a joint venture that formalized the relationship of the predecessors. A majority of the interests of the predecessors were in the same properties and the operations were under the combined management of Comstock Offshore and Bois d’Arc through the joint venture. As such, combined financial statements using historical cost basis more properly presents the historical combined operations of Comstock Offshore and the Bois d’Arc Participants. The acquisition of properties that Comstock Offshore made from a predecessor of Bois d’Arc was accounted for using the purchase method of accounting as these properties were not jointly developed under the exploration joint venture and because Bois d’Arc had significantly different investors in its exploration activities than its predecessor, the party from whom Comstock Offshore purchased certain properties that were contributed to us in our formation.

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

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

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the value of our common stock. The estimates of our proved oil and gas reserves used in preparation of our predecessors’ combined financial statements were determined by an independent petroleum engineering consulting firm and were prepared in accordance with the rules promulgated by the SEC and the Financial Accounting Standards Board (the “FASB”).

Impairment of oil and gas properties.  The determination of impairment of our oil and gas reserves is based on the oil and gas reserve estimates using projected future oil and natural gas prices that we have determined to be reasonable. The projected prices that we employ represent our long-term oil and natural gas price forecast and may be higher or lower than the December 31, 2005 market prices for crude oil and natural gas. For the impairment review of our oil and gas properties that we conducted as of December 31, 2005, we used oil and natural gas prices that were based on the current futures market. We used oil prices of $63.10, $64.01 and $62.80 per barrel for 2006, 2007 and 2008, respectively, and escalated prices by 3% each year thereafter to a maximum price of $66.60 per barrel. For natural gas, we used prices of $10.58, $10.04 and $9.11 per Mcf for 2006, 2007 and 2008, respectively, and escalated prices by 3% each year thereafter to a maximum price of $11.50 per Mcf. To the extent we had used lower prices in our impairment review, an impairment could have been indicated on certain of our oil and gas properties.

Accounting for asset retirement obligations.  We adopted Statement of Financial Accounting Standards No. 143 (“SFAS 143”) “Accounting for Asset Retirement Obligations,” on January 1, 2003. This statement requires us to record a liability in the period in which an asset retirement obligation (“ARO”) is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter, each quarter, this liability is accreted up to the final retirement cost. The adoption of SFAS 143 on January 1, 2003 resulted in a cumulative effect adjustment to record (i) a $4.5 million decrease in the carrying value of our oil and gas properties, (ii) a $1.2 million decrease in accumulated depreciation, depletion and amortization, (iii) a $2.6 million decrease in reserve for future abandonment, and (iv) a loss of $739,000 which was reflected as the cumulative effect of a change in accounting principle. The determination of our asset retirement obligations is based on our estimate of the future cost to plug and abandon our oil and gas wells and to dismantle and dispose of our offshore production facilities. The actual costs could be higher or lower than our current estimates.

Federal Taxation.  We became a taxable entity as a result of our conversion from a limited liability company to a corporation on May 10, 2005. While we were a limited liability company, taxable income was passed through to our unit owners. Our predecessors were either individuals, partnerships or limited liability companies that passed through their taxable income to their owners. Accordingly, provision for federal and state corporate income taxes have been made only with respect to our operations from May 10, 2005 through December 31, 2005. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon our conversion from a limited liability company to a corporation on May 10, 2005, we established a $108.2 million provision for deferred income taxes.

Stock-Based Compensation.  In connection with our formation, our unitholders approved our long-term incentive plan (the “Incentive Plan”) to provide for equity-based compensation for our executive officers, employees and consultants. As a private limited liability company, the nature of our equity awards was more complex than in a corporation. The initial awards made under the Incentive Plan were approved by the unit holders and were comprised of either (i) options to purchase class B units, representing a capital and profits interest in our company (when we were a limited liability company), or (ii) restricted class C units, representing solely a profits interest in our company (when we were a limited liability company). The only consultant who received an award under the Incentive Plan was Gayle Laufer, the spouse of our Chief Executive Officer. The Incentive Plan was amended and restated in connection with our conversion to a corporation in order to reflect our status as a corporation.

Our operating agreement (which was in effect while we were a limited liability company) set forth the rights of holders of class B units and class C units. A holder of an option for a class B unit had an interest similar to a stock option in a corporation. Since the option provided the holder with the right to acquire a class B unit when the option was exercised, the holder had the right to acquire both a capital and profits interest in us. The operating agreement provided that class C units were not entitled to any interest in our capital or our operating profits and losses. The

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operating agreement provided that, upon our conversion to a corporation, holders of class C units were allocated shares of restricted stock based on an increase in the value of the capital accounts. Class C units were converted into restricted shares of our common stock based on the formula prescribed in the operating agreement.

We account for employee equity-based compensation under the preferable fair value based method prescribed in Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the award vesting period. All of the awards made under the Incentive Plan vest over a five year period.

At the time of our formation, we granted to our employees options to purchase a total of 2,800,000 class B units at an exercise price of $6.00 per unit, which was equal to the value of the underlying class B unit at the time of grant, as determined by our board of managers at such time. We also awarded a total of 4,290,000 restricted class C units to our employees and consultants. At the time of issuance of the awards under the Incentive Plan, we did not obtain an independent valuation of the fair value of the units. Instead, we conducted a valuation based on the fair value of the assets contributed to us. Because the contributors used this approach in determining the value of their capital accounts upon our formation, we believed that it was appropriate to rely on it in determining the fair value of the Incentive Plan awards.

At the time of the Incentive Plan awards, we believed that the per share exercise price of the options for class B units represented the fair value of a Class B unit as of the grant date. However, in connection with the preparation of our financial statements and solely for purposes of accounting for employee stock-based compensation under SFAS 123, we reassessed the fair value of the stock-based awards made at the time of our formation.

In reassessing the fair value of the class B units and class C units underlying the equity awards granted, we used a valuation methodology that we believe is consistent with the practices recommended by the AICPA Audit and Accounting Practice Aid Series,Valuation of Privately-Held-Company Equity Securities Issued as Compensation(the “Practice Aid”). We reviewed the guidance set forth in the Practice Aid and we performed a retrospective valuation on a “top down” basis, using an enterprise valuation model. We determined the fair value of our company and then allocated the enterprise value to the various classes of member units. We also consulted with an independent valuation specialist regarding the methods and procedures used to determine, on a retrospective basis, the fair value of the class B units and the class C units at the time of issuance.

The enterprise valuation method we followed involved valuing the enterprise, and then using that value as a basis to value the enterprise’s privately issued securities. The valuation employed a probability-weighted expected return model. This model determines the value of a unit based upon an analysis of future values for the enterprise assuming various future outcomes. The value is based upon the probability-weighted present value of expected future investment returns, considering each of the possible future outcomes available to the enterprise. Although the future outcomes used in such a valuation must reflect the specific enterprise’s facts and circumstances, common future outcomes modeled would include an initial public offering, sale or merger, continued operation as a private enterprise, or dissolution.

We concluded that the “sale/merger” scenario and the “continued operation/remaining private” scenario were not realistic scenarios for our company. These outcomes were not considered realistic because we were organized as a limited liability company specifically for the reason that it could be “unwound” and liquidated without triggering adverse tax consequences to our contributors. The contributors established a procedure to liquidate the entity, with the intent to restore the parties to their original positions (as if the formation transaction had not occurred) if no initial public offering or similar financing transaction occurred. This indicated that neither a “sale/merger” or “continued operation/private entity” scenario was appropriate for this enterprise.

Our operating agreement provided that we would be liquidated if an initial public offering was not completed by a certain date. Our board of managers had to unanimously consent to any proposed extension of the date by which an initial public offering transaction was to be completed. If for any reason either Comstock or the Bois d’Arc Participants decided that the offering should have been abandoned, such party could have caused us to liquidate without incurring any liability to the other members. This requirement indicated that a “dissolution” scenario was

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appropriate and should have been considered a realistic outcome. Therefore, the enterprise valuation analyzed two future outcomes: an initial public offering and a dissolution.

In assessing the initial public offering outcome, the managing underwriter advised us that the shares were likely to be priced in a range from $12.00 to $15.00 per share in the offering, with a mid-point of $13.50. This range represented market expectations in February 2005 rather than in July 2004. The Practice Aid states that in the case of a retrospective valuation, care should be exercised to ensure that the assumptions and estimates underlying the valuation reflect only the business conditions, enterprise developments, and expectations that existed as of the valuation date. Therefore, in our valuation we adjusted the offering price range to reflect an expected range in July 2004. We believed that there was a significant increase in the market value of oil and natural gas reserves from July 2004 until February 2005, which is the most significant factor impacting the valuation of an exploration and production company. A study of oil and natural gas reserve sales that we had conducted indicated that values of oil and natural gas reserves increased by approximately 23% between July 2004 and February 2005. Our enterprise valuation adjusted for the increase in value that occurred subsequent to July 2004, resulting in an adjusted price range of $9.74 to $12.18 per share. The valuation utilized the mid-point of the range, $10.96, as a reasonable estimate of the expected value per share. This amount was then discounted to the time period that the offering was to take place using a risk-free interest rate of 4.0%. The valuation determined that the initial public offering scenario enterprise valuation was $563.0 million as of July 16, 2004.

Upon dissolution, the class B unit holders would have received a return of the assets contributed to us. We concluded that the net asset value of our company was $300.0 million at July 16, 2004, based on an analysis of the sale of comparable Gulf of Mexico reserves prior to our formation.

Our valuation analysis then considered numerous factors to assess the probability of completing a successful offering as of July 16, 2004, versus the probability of the alternative outcome of dissolution. A 70% probability was assigned to the initial public offering scenario and a 30% probability to the dissolution scenario. In arriving at a July 16, 2004 fair value for the class B and class C units, the valuation also considered that the scenarios described above did not consider that marketability would not be achieved for several months following the July 16, 2004 award date. At the valuation date, marketability was not certain. To reflect the delay and uncertainty in marketability, the valuation applied a 10% discount to estimate the inherent lack of marketability associated with the units.

The result of the new valuation was to increase the fair value of a class B unit at the issuance date from $6.00 per unit (based on an asset-based valuation) to $8.42 per unit (using a “top-down” enterprise valuation model).

The fair value of each option awarded under the Incentive Plan was estimated using the Black-Scholes option-pricing model with the following assumptions: (a) exercise price of $6.00 per unit, (b) fair value on the date of issuance of $8.42 per unit, (c) dividend yield of 0%, (d) expected volatility of 29.8%, (e) risk-free interest rate of 4.0%, and (f) expected life of 7.5 years. The resulting fair value of each option for a class B unit upon the date of grant was $4.55 per option.

The new valuation indicated that the fair value of each class C unit at the issuance date was $3.40 per unit. In determining the allocation of the enterprise valuation to the various classes of equity, we considered the rights of the class C unitholders in each scenario, the initial public offering scenario and the dissolution scenario. In the initial public offering scenario, we considered the formula for conversion of class C units to shares of common stock upon our conversion from a limited liability company to a corporation. Our operating agreement provided that each class C unit would be converted into no more than one-half of one share of common stock. In allocating the enterprise value between the classes of equity, we assumed the maximum value for class C units, which meant that the class C units issued would have the value of one-half of a class B unit. In the dissolution scenario, we considered that there would be no appreciation in the enterprise, and therefore the class C units would have no value. After applying the probability weighting described above to the expected returns of the class C units, and the 10% discount for lack of marketability of the units, we determined that the fair value for each class C unit was $3.40.

We believed there were three factors that contributed to the increase in the value of a unit (or, at the time of the initial public offering, a share of common stock) over its value at our formation on July 16, 2004, when the awards were granted. The first factor was the increase of approximately 23% in the market value of oil and natural gas reserves subsequent to our formation. The second factor was the enhanced marketability and liquidity of our

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common stock attributable to the public offering, which contributed significantly to the increased value. The third factor was that at the time of the Incentive Plan awards, there was considerable uncertainty regarding whether we would be able to arrange for a financing transaction, such as an initial public offering, as contemplated by our operating agreement, which would result in our liquidation. Therefore, the fair value of the units awarded in July 2004 took into account the probability of whether the initial public offering would be completed and the probability of an alternative scenario, namely, a dissolution. In that event, the class B options and class C units would have no value as none of the awards would have vested.

New accounting standards.  On December 16, 2004, the FASB issued Statement 123 (revised 2004), “Share-Based Payment” (“SFAS 123 R”) that requires compensation costs related to share-based payment transactions (issuance of stock options and restricted stock) to be recognized in the financial statements. With limited exceptions, the amount of compensation cost is to be measured based on the grant date fair value of the equity or liability instruments issued. Compensation cost is recognized over the period that an employee provides service in exchange for the award. Statement 123 R replaces SFAS 123, “Accounting for Stock-Based Compensation”, and supersedes APB 25. SFAS 123 R is effective for the first reporting period after June 15, 2005. Entities that use the fair value-based method for either recognition or disclosure under SFAS 123 are required to apply SFAS 123 R using a modified version of prospective application whereby the entity is required to record compensation expense for all awards it grants after the date of adoption and the unvested portion of previously granted awards that remain outstanding at the date of adoption. We adopted the fair value-based measure as proscribed in SFAS 123 using the modified prospective application effective January 1, 2004. Therefore, SFAS 123 R will not have a significant impact on us.

ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

Oil and Natural Gas Prices

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for crude oil, the foreign supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on our oil and natural gas production in 2005, a $1.00 change in the price per barrel of oil would have resulted in a change in our cash flow for such period by approximately $1.1 million and a $1.00 change in the price per Mcf of natural gas would have changed our cash flow by approximately $14.8 million.

Interest Rates

At December 31, 2005, we had $69.0 million outstanding under our bank credit facility, which is subject to floating market rates of interest. Borrowings under the bank credit facility bear interest at a fluctuating rate that is tied to LIBOR or the corporate base rate, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow. Based on borrowings outstanding at December 31, 2005, a 100 basis point change in interest rates would change our interest expense on our variable rate debt by approximately $0.7 million.

ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our combined and consolidated financial statements are included onpages F-1 toF-23 of this report.

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

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

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

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

None.

ITEM 9A.   CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures.  Our chief executive officer and our chief financial officer have evaluated, as required byRule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), our disclosure controls and procedures (as defined in Exchange ActRule 13a-15(e)) as of the end of the period covered by this Annual Report onForm 10-K. Based on that evaluation, our chief executive officer and chief financial officer concluded that the design and operation of our disclosure controls and procedures are adequate and effective in ensuring that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Changes in internal control over financial reporting.  There were no changes in our internal control over financial reporting (as defined inRule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.   OTHER INFORMATION

None.

PART III

ITEM 10.   DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2005.

Code of Ethics.  We have a Code of Business Conduct and Ethics that is applicable to all of our directors, officers and employees as required by New York Stock Exchange rules. We also have a Code of Ethics for Senior Financial Officers that is applicable to our Chief Executive Officer and senior financial officers. Both the Code of Business Conduct and Ethics and Code of Ethics for Senior Financial Officers may be found on our website at www.boisdarcenergy.com. Both of these documents are also available, without charge, to any stockholder upon request to: Bois d’Arc Energy, Inc., Attn: Investor Relations, 600 Travis Street, Suite 5200, Houston, TX 75022(713) 228-0438. We intend to disclose any amendments or waivers to these codes that apply to our Chief Executive Officer and senior financial officers on our website in accordance with applicable SEC rules. Please see the

46

definitive proxy statement for our 2006 annual meeting, which will be filed with the SEC within 120 days of December 31, 2005 for additional information regarding our corporate governance policies.

ITEM 11.   EXECUTIVE COMPENSATION

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2005.

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

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2005.

ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2005.

ITEM 14.   PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2005.

PART IV

ITEM 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements:

1. The following combined and consolidated financial statements and notes are included on Pages F-2 to F-23 of this report.

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2004 and 2005	F-3
Combined Statements of Operations for the Year Ended December 31, 2003 and the period from January 1, 2004 to July 15, 2004 and Consolidated Statements of Operations for the period from Inception (July 16, 2004) to December 31, 2004 and the Year Ended December 31, 2005	F-4
Combined Statement of Changes in Equity for the Year Ended December 31, 2003, Consolidated Statement of Changes in Members’ Equity for the Year Ended December 31, 2004 and Consolidated Statement of Changes in Members’ and Stockholders’ Equity for the Year Ended December 31, 2005	F-5
Combined Statements of Cash Flows for the Year Ended December 31, 2003 and the period from January 1, 2004 to July 15, 2004 and Consolidated Statements of Cash Flows for the period from Inception (July 16, 2004) to December 31, 2004 and the Year Ended December 31, 2005	F-6
Notes to Combined and Consolidated Financial Statements	F-7

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

47

(b) Exhibits:

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

Exhibit No.			Description
	2	.1	Contribution Agreement, dated as of July 16, 2004, by and among Bois d’Arc Energy, LLC, Bois d’Arc Properties, LP, Bois d’Arc Resources, Ltd., Wayne L. Laufer, Gary W. Blackie, Haro Investments LLC, Comstock Offshore, LLC, Comstock Resources, Inc. and such other persons listed on the signature pages thereto (incorporated by reference to Exhibit 10.2 to Comstock Resources, Inc.’s Quarterly Report onForm 10-Q for the quarter ended June 30, 2004 (FileNo. 0-16741)).
	3	.1	Articles of Incorporation (incorporated by reference to Exhibit 3.1 to our Quarterly Report onForm 10-Q for the quarter ended March 31, 2005).
	3	.2	Bylaws (incorporated by reference to Exhibit 3.5 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	3	.3	Articles of Organization of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.1 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	3	.4	Amended and Restated Operating Agreement, dated as of August 23, 2004 to be effective July 16, 2004, of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.2 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	3	.5	First Amendment, dated as of September 29, 2004, to the Amended and Restated Operating Agreement of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.3 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	3	.6	Second Amendment, dated as of January 26, 2005, to the Amended and Restated Operating Agreement of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.6 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	3	.7	Third Amendment, effective as of July 16, 2004, to the Amended and Restated Operating Agreement of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.7 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	3	.8	Fourth Amendment, dated as of April 13, 2005, to the Amended and Restated Operating Agreement of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.8 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	3	.9	Fifth Amendment, effective as of July 16, 2004, to the Amended and Restated Operating Agreement of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.9 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	4	.1	Specimen Stock Certificate of Common Stock (incorporated by reference to Exhibit 4.3 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	10	.1#	Amended and Restated Long-Term Incentive Plan of Bois d’Arc Energy, Inc. (incorporated by reference to Exhibit 10.2 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	10	.2#	Form of Option Agreement under the Bois d’Arc Energy, Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to our Quarterly Report onForm 10-Q for the quarter ended March 31, 2005).
	10	.3#	Form of Restricted Stock Agreement under the Bois d’Arc Energy, Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 99.2 to our Quarterly Report onForm 10-Q for the quarter ended March 31, 2005).
	10	.4#	Employment Agreement, dated as of July 16, 2004, between Bois d’Arc Energy, LLC and Gary W. Blackie (incorporated by reference to Exhibit 10.3 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	10	.5#	Employment Agreement, dated as of July 16, 2004, between Bois d’Arc Energy, LLC and Wayne L. Laufer (incorporated by reference to Exhibit 10.4 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	10	.6	Credit Agreement dated May 11, 2005 between Bois d’Arc Energy, Inc., and the Bank of Nova Scotia as Administrative Agent and Issuing Bank, Calyon New York Branch, as Syndication Agent, AmSouth Bank as Documentation Agent and the other lenders (incorporated by reference to Exhibit 10.1 to our Quarterly Report onForm 10-Q for the quarter ended March 31, 2005).

48

Exhibit No.			Description
	10	.7	Loan Agreement, dated as of July 16, 2004, by and between Comstock Resources, Inc., as lender, and Bois d’Arc Energy, LLC, Bois d’Arc Properties, LP, and Bois d’Arc Offshore, Ltd., as borrower (incorporated reference to Exhibit 10.4 to Comstock Resources, Inc.’s Quarterly Report onForm 10-Q for the quarter ended June 30, 2004 (FileNo. 0-16741)).
	10	.8	Services Agreement, dated as of July 16, 2004, between Comstock Resources, Inc. and Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 10.3 to Comstock Resources, Inc.’s Quarterly Report onForm 10-Q for the quarter ended June 30, 2004 (File No.0-16741)).
	10	.9	Lease Agreement dated December 1, 2004 between Texas Tower Limited and Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 10.8 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	21	*	List of Subsidiaries.
	23	.1*	Consent of Ernst & Young LLP.
	23	.2*	Consent of Lee Keeling and Associates, Inc.
	31	.1*	Chief Executive Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31	.2*	Chief Financial Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32	.1+	Chief Executive Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
	32	.2+	Chief Financial Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.

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

49

SIGNATURES

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

BOIS d’ARC ENERGY, INC.

By:  /s/  WAYNE L. LAUFER

Wayne L. Laufer

Chief Executive Officer

(Principal Executive Officer)

Date: March 16, 2006

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

/s/  M. JAY ALLISON M. Jay Allison	Chairman of the Board of Directors	March 16, 2006
/s/  WAYNE L. LAUFER Wayne L. Laufer	Chief Executive Officer and Director (Principal Executive Officer)	March 16, 2006
/s/  GARY W. BLACKIE Gary W. Blackie	President and Director	March 16, 2006
/s/  ROLAND O. BURNS Roland O. Burns	Senior Vice President, Chief Financial Officer, Secretary, Treasurer and Director (Principal Financial and Accounting Officer)	March 16, 2006
/s/  JOHN L. DUVIEILH John L. Duvieilh	Director	March 16, 2006
/s/  D. MICHAEL HARRIS D. Michael Harris	Director	March 16, 2006
/s/  DAVID K. LOCKETT David K. Lockett	Director	March 16, 2006
/s/  CECIL E. MARTIN, JR. Cecil E. Martin, Jr.	Director	March 16, 2006
/s/  DAVID W. SLEDGE David W. Sledge	Director	March 16, 2006

50

INDEX

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2004 and 2005	F-3
Combined Statements of Operationsfor the Year Ended December 31, 2003 and the period from January 1, 2004 to July 15, 2004 and Consolidated Statements of Operations for the period from Inception (July 16, 2004) to December 31, 2004 and the Year Ended December 31, 2005	F-4
Combined Statement of Changes in Equity for the Year Ended December 31, 2003, Consolidated Statement of Changes in Members’ Equity for the Year Ended December 31, 2004 and Consolidated Statement of Changes in Members’ and Stockholders’ Equity for the Year Ended December 31, 2005	F-5
Combined Statements of Cash Flowsfor the Year Ended December 31, 2003 and the period from January 1, 2004 to July 15, 2004 and Consolidated Statements of Cash Flows for the period from Inception (July 16, 2004) to December 31, 2004 and the Year Ended December 31, 2005	F-6
Notes to Combined and Consolidated Financial Statements	F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of Bois d’Arc Energy, Inc.

We have audited the accompanying consolidated balance sheets of Bois d’Arc Energy, Inc. and subsidiaries as of December 31, 2004 and 2005 and the related combined statements of operations, changes in equity and cash flows of the Bois d’Arc Energy Predecessors for the year ended December 31, 2003, and the period from January 1, 2004 to July 15, 2004 and the related consolidated statements of operations, changes in equity and cash flows of Bois d’Arc Energy, Inc. for the period from Inception (July 16, 2004) to December 31, 2004 and the year ended December 31, 2005. These financial statements are the responsibility of the management of Bois d’Arc Energy, Inc. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of Bois d’Arc Energy Inc.’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Bois d’Arc Energy Inc.’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Bois d’Arc Energy, Inc. and subsidiaries at December 31, 2004 and 2005 and the combined results of the Bois d’Arc Energy Predecessors’ operations, changes in equity and their cash flows for the year ended December 31, 2003 and the period from January 1, 2004 to July 15, 2004, and the consolidated results of operations, changes in equity and cash flows of Bois d’Arc Energy, Inc. and subsidiaries for the period from Inception (July 16, 2004) to December 31, 2004 and the year ended December 31, 2005 in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligationsand on January 1, 2004 the Company changed its method of accounting for employee stock based compensation to the fair value based method.

ERNST & YOUNG LLP

March 13, 2006

Dallas, Texas

F-2

BOIS d’ARC ENERGY, INC

CONSOLIDATED BALANCE SHEETS

As of December 31, 2004 and 2005

	December 31,
	2004			2005
	(In thousands)
ASSETS
Cash and cash equivalents	$	2,416		$	12,043
Accounts receivable:
Oil and gas sales		9,140			25,520
Joint interest operations		5,558			8,364
Other current assets		1,476			4,245
Total current assets		18,590			50,172
Oil and gas properties, using successful efforts accounting:
Proved properties		291,227			299,947
Unproved properties		8,566			13,533
Wells and related equipment and facilities		444,403			620,777
Accumulated depreciation, depletion and amortization		(233,243	)		(274,434	)
Net oil and gas properties		510,953			659,824
Other property and equipment, net of accumulated depreciation of $1,436 and $875 at December 31, 2004 and 2005, respectively		524			2,107
Other assets		516			799
	$	530,583		$	712,902
LIABILITIES AND EQUITY
Accounts payable		20,103			48,005
Accrued expenses		14,676			18,401
Total current liabilities		34,779			66,406
Bank credit facility		—			69,000
Payable to Comstock Resources		148,066			—
Deferred income taxes payable		—			123,256
Reserve for future abandonment costs		28,253			35,034
Commitments and contingencies
Stockholders’ and members’ equity:
Class A Units, 10,000 units outstanding at December 31, 2004		10			—
Class B Units, 50,000,000 units outstanding at December 31, 2004		304,227			—
Common stock, $0.01 par, 100,000,000 shares authorized, 64,155,000 outstanding at December 31, 2005		—			642
Additional paid-in capital		—			454,988
Retained earnings (deficit)		15,248			(36,424	)
Total stockholders’ equity		319,485			419,206
	$	530,583		$	712,902

The accompanying notes are an integral part of these statements.

F-3

BOIS d’ARC ENERGY, INC.
BOIS d’ARC ENERGY PREDECESSORS

COMBINED STATEMENTS OF OPERATIONS

For the Year Ended December 31, 2003 and the Period from January 1, 2004 to July 15, 2004

CONSOLIDATED STATEMENT OF OPERATIONS
For the Period from Inception (July 16, 2004) to December 31, 2004
and for the Year Ended December 31, 2005

	Combined Bois d’Arc Energy
	Predecessors						Bois d’Arc Energy
							Period from
				Period from			Inception
				January 1,			(July 16,
	Year Ended			2004 to			2004) to			Year Ended
	December 31,			July 15,			December 31,			December 31,
	2003			2004			2004			2005
	(Amounts in thousands except per share amounts)
Oil and gas sales	$	133,450		$	70,341		$	72,721		$	184,436
Operating expenses:
Oil and gas operating		22,290			15,233			16,602			37,089
Exploration		800			2,676			12,040			16,794
Depreciation, depletion and amortization		44,285			22,831			21,761			42,854
Impairment		500			—			—			590
General and administrative, net		3,481			1,450			2,641			9,331
Total operating expenses		71,356			42,190			53,044			106,658
Income from operations		62,094			28,151			19,677			77,778
Other income (expense):
Interest income		154			75			74			222
Interest expense		(9,580	)		(4,453	)		(2,665	)		(3,775	)
Formation costs		—			—			(1,838	)		—
Loss on sale of assets		—			—			—			(89	)
Total other income (expense)		(9,426	)		(4,378	)		(4,429	)		(3,642	)
Net income before income taxes		52,668			23,773			15,248			74,136
Provision from income taxes		—			—			—			(125,808	)
Net income before cumulative effect of change in accounting principle		52,668			23,773			15,248			(51,672	)
Cumulative effect of change in accounting principle		(739	)		—			—			—
Net income	$	51,929		$	23,773		$	15,248		$	(51,672	)
Income (loss) per share (unit):
Basic							$	0.30		$	(0.89	)
Diluted							$	0.30		$	(0.89	)
Weighted average common and common stock equivalent (units) shares outstanding:
Basic								50,000			57,909
Diluted								50,485			57,909
Pro forma computation related to conversion to a corporation for income tax purposes:
Income before income taxes	$	52,668		$	23,773		$	15,248		$	74,136
Pro forma provision for income taxes		(18,434	)		(8,321	)		(5,807	)		(26,914	)
Pro forma net income	$	34,234		$	15,452		$	9,441		$	47,222
Pro forma earnings per share (unit):
Basic							$	0.19		$	0.82
Diluted							$	$0.19		$	0.79
Weighted average common and common stock equivalent shares (units) outstanding:
Basic								50,000			57,909
Diluted								50,485			59,655

The accompanying notes are an integral part of these statements.

F-4

BOIS d’ARC ENERGY, INC.
BOIS d’ARC ENERGY PREDECESSORS

COMBINED STATEMENTS OF CHANGES IN EQUITY

For the Year Ended December 31, 2003

and the Period from January 1, 2004 to July 15, 2004

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’ AND STOCKHOLDERS’ EQUITY

For the Period from Inception (July 16, 2004) to December 31, 2004 and

For the Year Ended December 31, 2005

	Combined Bois d’Arc Energy
	Predecessors									Bois d’Arc Energy
																		Additional			Retained
	Comstock			Bois d’Arc						Class A			Class B			Common		Paid In			Earnings
	Offshore			Participants			Combined			Units			Units			Stock		Capital			(Deficit)			Total
	(In thousands)
Balance at December 31, 2002	$	(36,018	)	$	55,150		$	19,132		$	—		$	—		$	—	$	—		$	—		$	—
Distributions to owners		—			(6,112	)		(6,112	)		—			—			—		—			—			—
Net income		22,817			29,112			51,929			—			—			—		—			—			—
Balance at December 31, 2003		(13,201	)		78,150			64,949			—			—			—		—			—			—
Distributions to owners		—			(946	)		(946	)		—			—			—		—			—			—
Contributions of assets, net of liabilities assumed		(370	)		(87,406	)		(87,776	)		10			304,227			—		—			—			304,237
Net income		13,571			10,202			23,773			—			—			—		—			15,248			15,248
Balance at December 31, 2004		—			—			—			10			304,227			—		—			15,248			319,485
Conversion from LLC to a corporation		—			—			—			(10	)		(304,227	)		500		303,727			—			(10	)
Public offering of common stock		—			—			—			—			—			120		144,960			—			145,080
Stock issuance costs		—			—			—			—			—			—		(1,818	)		—			(1,818	)
Stock-based compensation		—			—			—			—			—			22		8,119			—			8,141
Net income (loss)		—			—			—			—			—			—		—			(51,672	)		(51,672	)
Balance at December 31, 2005	$	—		$	—		$	—		$	—		$	—		$	642	$	454,988		$	(36,424	)	$	419,206

The accompanying notes are an integral part of these statements.

F-5

BOIS d’ARC ENERGY, INC.
BOIS d’ARC ENERGY PREDECESSORS

COMBINED STATEMENTS OF CASH FLOWS

For the Year Ended December 31, 2003

and the Period from January 1, 2004 to July 15, 2004

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Period from Inception (July 16, 2004) to December 31, 2004 and

For the Year Ended December 31, 2005

	Combined Bois d’Arc Energy
	Predecessors						Bois d’Arc Energy
							Period from
				Period from			Inception
				January 1,			(July 16,
	Year Ended			2004 to			2004) to			Year Ended
	December 31,			July 15,			December 31,			December 31,
	2003			2004			2004			2005
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	51,929		$	23,773		$	15,248		$	(51,672	)
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of change in accounting principle		739			—			—			—
Deferred income taxes		—			—			—			123,256
Stock based compensation		—			—			2,506			5,635
Amortization of loan costs		—			—			—			141
Loss on sale of assets		—			—			—			89
Depreciation, depletion and amortization		44,285			22,831			21,761			42,854
Impairments		500			—			—			590
Dry hole costs and lease impairments		72			1,527			10,892			2,353
Increase in accounts receivable		(10,974	)		(8,659	)		7,282			(19,186	)
Decrease (increase) in other current assets		1,567			(199	)		(1,464	)		(2,769	)
Increase in accounts payable and accrued expenses		25,883			11,715			(6,776	)		34,132
Net cash provided by operating activities		114,001			50,988			49,449			135,423
CASH FLOWS FROM INVESTING ACTIVITIES:
Formation of Bois d’Arc Energy, net of cash distributed		—			—			(24,054	)		—
Capital expenditures		(98,974	)		(83,273	)		(59,703	)		(189,771	)
Proceeds from sale of assets		—			—			—			160
Net cash used for investing activities		(98,974	)		(83,273	)		(83,757	)		(189,611	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from Comstock Resources		4,293			31,649			64,889			16,000
Repayments to Comstock Resources		—			—			—			(164,066	)
Borrowings under bank credit facility		—			—			—			126,000
Repayments under bank credit facility		(3,500	)		(1,944	)		(28,175	)		(57,000	)
Proceeds from issuance of Class A Units		—			—			10			—
Redemption of Class A Units		—			—			—			(10	)
Proceeds from issuance of common stock		—			—			—			145,080
Stock and debt issuance costs		—			—			—			(2,189	)
Distributions to equity owners		(6,112	)		(946	)		—			—
Net cash provided by (used for) financing activities		(5,319	)		28,759			36,724			63,815
Net increase (decrease) in cash and cash equivalents		9,708			(3,526	)		2,416			9,627
Cash and cash equivalents, beginning of period		12,311			22,019			—			2,416
Cash and cash equivalents, end of period	$	22,019		$	18,493		$	2,416		$	12,043
Cash paid for interest payments	$	598		$	218		$	2,665		$	3,270
Cash paid for income taxes	$	—		$	—		$	—		$	1,600

The accompanying notes are an integral part of these statements.

F-6

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS

(1)   Organization

Bois d’Arc Energy, Inc. (“Bois d’Arc Energy” or the “Company”) is engaged in oil and natural gas exploration, development and production in state and federal waters in the Gulf of Mexico and is the successor to Bois d’Arc Energy, LLC following its conversion from a limited liability company to a corporation on May 10, 2005. References herein to “Bois d’Arc Energy” or the “Company” include Bois d’Arc Energy, LLC prior to its conversion to a corporation.

In December 1997, Comstock Offshore LLC (“Comstock Offshore”), an indirect wholly-owned subsidiary of Comstock Resources, Inc. (“Comstock”), acquired from Bois d’Arc Resources and other interest owners certain offshore oil and natural gas properties, including the properties the Company now owns at Ship Shoal blocks 66, 67, 68 and 69 and South Pelto block 1. Bois d’Arc was a predecessor in interest to Bois d’Arc Resources, Ltd., an entity owned by two of the Company’s executive officers, directors and stockholders, Gary W. Blackie and Wayne L. Laufer. In connection with the December 1997 acquisition, Comstock Offshore and Bois d’Arc established a joint exploration venture to explore for oil and natural gas in the Gulf of Mexico. Under the joint exploration venture, Bois d’Arc was responsible for developing a budget for exploration activities and for generating exploration prospects in the Gulf of Mexico utilizing3-D seismic data and their extensive geological expertise in the region. Comstock Offshore had to approve the budget and would advance the funds for the acquisition of3-D seismic data and leases needed to conduct exploration activities. Comstock Offshore was reimbursed for all advanced costs and was entitled to a non-promoted working interest in each prospect generated. For each successful discovery well drilled pursuant to the joint exploration venture, Comstock issued to the two principals of Bois d’Arc warrants exercisable for the purchase of shares of Comstock’s common stock. Successful wells drilled under the exploration venture were operated by Bois d’Arc Offshore, Ltd. pursuant to a joint operating agreement entered into by the parties participating in the prospect, including Comstock Offshore and the Bois d’Arc Participants. Any future operation on the lease including drilling additional wells on the acreage associated with the prospect was conducted under the joint operating agreement and had to be approved by the participating parties.

On July 16, 2004, Comstock, Bois d’Arc Resources, Ltd. and Messrs. Blackie and Laufer formed the Company to replace the joint exploration venture. Bois d’Arc Resources, Ltd., Bois d’Arc Offshore, Ltd., and the other entities owned by Messrs. Blackie and Laufer and who are collectively referred to as “Bois d’Arc,” and certain participants in their exploration activities, who are collectively referred to as the “Bois d’Arc Participants,” and Comstock Offshore contributed to the Company substantially all of their Gulf of Mexico properties and assigned to the Company their related liabilities, including certain debt, in exchange for equity interests in the Company. The Bois d’Arc Participants and Comstock Offshore are collectively referred to as the “Bois d’Arc Energy Predecessors.” The equity interests issued in exchange for the contributions were determined by using a valuation of the properties contributed by the particular contributors conducted by Lee Keeling and Associates, Inc., independent petroleum consultants, relative to the value of the properties contributed by all contributors. Comstock Offshore contributed its Gulf of Mexico properties and assigned $83.2 million of related debt in exchange for an approximately 60% ownership interest. Each of the Bois d’Arc Participants contributed its interest in commonly owned Gulf of Mexico properties and they assigned in the aggregate $28.2 million of related liabilities in exchange for an approximately 40% aggregate ownership interest. The Bois d’Arc Participants also received $27.6 million in cash to equalize the amount that Comstock Offshore’s debt exceeded its proportional share of the liabilities assigned. Bois d’Arc Energy also reimbursed Comstock Offshore $12.7 million and Bois d’Arc $0.8 million for advances made under the exploration joint venture for undrilled prospects.

The formation of the Company was a continuation of the joint exploration venture as the owners and principals of the same parties, Comstock Offshore and Bois d’Arc, are continuing to explore for oil and gas in the Gulf of Mexico with the same business objectives and the same management team. In addition, all of the oil and gas properties developed under the joint exploration venture were contributed to the Company. The formation of the

F-7

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Company changed the legal structure of the partnership between Comstock Offshore and Bois d’Arc but did not change the underlying business operations of the joint exploration program that began in late 1997.

The following table presents the assets and liabilities of Comstock Offshore and the Bois d’Arc Participants that were contributed to Bois d’Arc Energy at its formation:

	Contributed to
	Bois d’Arc
	Energy
	(In thousands)
Cash	$	17,030
Other current assets		21,992
Property and equipment, net		482,697
Total assets		521,719
Current liabilities and bank loan		(66,788	)
Payable to Comstock Resources		(83,177	)
Reserve for future abandonment		(26,443	)
Total liabilities		(176,408	)
Net assets		345,311
Cash distributed		(41,084	)
Net contribution	$	304,227

During the time Bois d’Arc Energy was a limited liability company, it had three classes of membership units — class A, class B and class C units. Class A units represented an interest in the capital of the Company but no interest in the profits of the Company and had voting rights. Class B units represented an interest in the capital and profits of the Company and had no voting or other decision-making rights except as required by applicable law. Class C units represented an interest only in the profits of the Company and had no voting or other decision-making rights except as required by applicable law.

(2)   Summary of Significant Accounting Policies

Accounting policies used by Bois d’Arc Energy reflect oil and gas industry practices and conform to accounting principles generally accepted in the United States of America.

Basis of Presentation

The accompanying financial statements reflect the consolidated results of the Company, including the financial position as of December 31, 2004 and 2005, the results of operations and cash flows for the period from Inception through December 31, 2004 and for the year ended December 31, 2005, and the combined results of operations and cash flows of the Bois d’Arc Energy Predecessors for the year ended December 31, 2003 and for the period from January 1, 2004 to July 15, 2004. The Bois d’Arc Energy Predecessors commenced operations as a joint venture on December 9, 1997 with the formation of Comstock Offshore, its acquisition of certain oil and natural gas properties from a predecessor of Bois d’Arc and the establishment of the joint exploration venture. The Bois d’Arc Energy Predecessors combined their respective Gulf of Mexico offshore properties into Bois d’Arc Energy, a newly formed limited liability company until its conversion to a corporation on May 10, 2005. Comstock Offshore and Bois d’Arc conducted joint exploration activities continuously for seven and one-half years and had interests in the same offshore properties. At the time of its formation, ownership in Bois d’Arc Energy was based on the relative values of the properties that each entity contributed, approximately 60% by Comstock and 40% by the Bois d’Arc

F-8

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Participants. The operating agreement of Bois d’Arc Energy provided that the board was to be composed of four persons, two of which were appointed by Comstock Offshore and two of which were appointed by the Bois d’Arc Participants. A majority of the board of managers was required to take any action of the board of managers (thereby requiring at least one of the managers appointed by the other group to effect any decision), and all significant matters required unanimous consent of the managers. Accordingly, prior to its conversion to a corporation, Bois d’Arc Energy was jointly controlled and managed. There was an ongoing interest of both companies in the partnership and a sharing of management.

The substance of the formation of the Company was that Comstock Offshore and the Bois d’Arc Participants pooled their separate interests in various properties for a single interest in an entity that holds all of their separate offshore properties. Management of the resulting joint venture was consistent with that in place during the term of the joint exploration venture. The Company was initially operated as a joint venture and the net assets of the predecessors were recorded at historical cost on the formation. The accompanying combined financial statements of the Bois d’Arc Energy Predecessors present the results of operations for the year ended December 31, 2003 and for the period from January 1, 2004 to July 15, 2004 of Comstock Offshore and the Bois d’Arc Participants as they related to the properties contributed to the Company on a combined basis.

Principles of Consolidation

The consolidated financial statements include the accounts of Bois d’Arc Energy and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its undivided interest in properties using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are included in its consolidated financial statements.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from those estimates. Changes in the future estimated oil and natural gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analysis could have a significant impact on the future results of operations.

Concentration of Credit Risk and Accounts Receivable

Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and cash equivalents, and accounts receivable. Bois d’Arc Energy places its cash with high credit quality financial institutions and its derivative financial instruments with financial institutions and other firms that management believes have high credit rating. Substantially all of Bois d’Arc Energy’s accounts receivable are due from either purchasers of oil and natural gas or participants in oil and natural gas wells for which Bois d’Arc Energy serves as the operator. Generally, operators of oil and natural gas wells have the right to offset future revenues against unpaid charges related to operated wells. Oil and gas sales are generally unsecured. The Company’s credit losses consistently have been within management’s expectations. Bois d’Arc Energy has not had any credit losses in the past and believes its accounts receivable are fully collectable. Accordingly, no allowance for doubtful accounts has been provided.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, accounts receivable, other current assets and accounts payable and accrued expenses approximate fair value due to the short maturity of these instruments.

F-9

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Property and Equipment

Bois d’Arc Energy follows the successful efforts method of accounting for its oil and gas properties. Acquisition costs for proved oil and gas properties, costs of drilling and equipping productive wells and costs of unsuccessful development wells are capitalized and amortized on an equivalentunit-of-production basis over the life of the remaining related oil and natural gas reserves. Equivalent units are determined by converting oil to natural gas at the ratio of six barrels of oil for one thousand cubic feet of natural gas. Wells sharing common production platforms and facilities comprise the cost centers which are used for amortization purposes. The estimated future costs of dismantlement, restoration and abandonment are included in the combined balance sheets in the reserve for future abandonment costs and expensed as part of depreciation, depletion and amortization expense. Costs incurred to acquire oil and gas leases are capitalized. Unproved oil and natural gas properties are periodically assessed and any impairment in value is charged to exploration expense. The costs of unproved properties which are determined to be productive are transferred to proved oil and natural gas properties and amortized on an equivalentunit-of-production basis. Exploratory expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and natural gas properties, are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property but charged to expense if and when the well is determined not to have found proved oil and natural gas reserves. In accordance with Statement of Financial Accounting Standards No. 19, exploratory drilling costs are evaluated within a one-year period after the completion of drilling.

In accordance with the Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), Bois d’Arc Energy assesses the need for an impairment of the costs capitalized of its oil and gas properties on a property or cost center basis. If an impairment is indicated based on undiscounted expected future cash flows, then an impairment is recognized to the extent that net capitalized costs exceed discounted expected future cash flows based on escalated prices. In 2003 and 2005, Bois d’Arc Energy had a $0.5 million and $0.6 million, respectively, impairment of its oil and gas properties which primarily related to some minor valued fields where an impairment was indicated based on estimated future cash flows attributable to the fields’ estimated proved oil and natural gas reserves. Other property and equipment consists primarily of computer equipment and furniture and fixtures which are depreciated over estimated useful lives ranging from three to ten years on a straight-line basis.

Segment Reporting

Bois d’Arc Energy presently operates in one business segment, the exploration and production of oil and natural gas in the Gulf of Mexico.

Major Purchasers

During the year ended December 31, 2005, the Company had two purchasers of its oil and natural gas production which individually accounted for 10% or more of total oil and gas sales. During 2005 these purchasers accounted for 49% and 33% of total oil and gas sales, respectively. From Inception through December 31, 2004, Bois d’Arc Energy had two purchasers of its oil and natural gas production which individually accounted for 10% or more of total oil and gas sales, and such purchasers accounted for 46% and 37% of total oil and gas sales, respectively. For the period from January 1, 2004 to July 15, 2004 the same purchasers accounted for 42% and 41% of total oil and gas sales, respectively. Three purchasers of oil and natural gas production accounted for 32%, 24% and 23% of total 2003 oil and gas sales, respectively.

Revenue Recognition and Gas Balancing

Bois d’Arc Energy utilizes the sales method of accounting for natural gas revenues whereby revenues are recognized based on the amount of gas sold to purchasers. The amount of gas sold may differ from the amount to

F-10

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

which the Company is entitled based on its revenue interests in the properties. Bois d’Arc Energy did not have any significant imbalance positions at December 31, 2003, 2004 or 2005.

General and Administrative Expense

General and administrative expense is reduced by operating fee income received by the Company, as follows:

							Period from
							Inception
				Period from			(July 16,
	Year Ended			January 1,			2004) to			Year Ended
	December 31,			2004 to July 15,			December 31,			December 31,
	2003			2004			2004			2005
	(In thousands)
General and administrative expense	$	6,266		$	3,514		$	4,303		$	12,364
Operating fee income	$	(2,785	)	$	(2,064	)	$	(1,662	)	$	(3,033	)
General and administrative expense, net	$	3,481		$	1,450		$	2,641		$	9,331

The operating fee income is a reimbursement of the Company’s general and administrative expense. As the parent of Comstock Offshore, Comstock provided certain general and administrative services for Comstock Offshore prior to the Company’s formation. The allocation of Comstock’s general and administrative services to Comstock Offshore by Comstock was based on the percentage of sales of Comstock Offshore as compared to the consolidated sales of all of Comstock’s subsidiaries. Management of Comstock believes this allocation method was reasonable and appropriate for attributing corporate overhead costs to the activities of its operating subsidiaries. Management estimated that the allocated costs would have been similar if Comstock Offshore had operated as an unaffiliated entity. The accompanying financial statements include $3.7 million and $2.2 million of general and administrative expense allocated to Comstock Offshore by Comstock for 2003 and 2004, respectively.

General and administrative expenses for the period from Inception to December 31, 2004, and for the year ended December 31, 2005 include $120,000 and $150,000, respectively, paid by Bois d’Arc Energy to Comstock for accounting services under a service agreement.

Stock-based Compensation

The Company follows the fair value based method prescribed in Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”) in accounting for equity-based compensation. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period.

Income Taxes

The Bois d’Arc Energy Predecessors are either individuals or partnerships or limited liability companies that pass through their taxable income to their owners. From the date of its formation until its conversion to a corporation on May 10, 2005, Bois d’Arc Energy was a limited liability company that passed through its taxable income to its members. Accordingly, no provision for federal or state corporate income taxes was made in the accompanying financial statements for periods prior to May 10, 2005.

Bois d’Arc Energy became a taxable entity as a result of its conversion from a limited liability company to a corporation on May 10, 2005. Bois d’Arc Energy accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as

F-11

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the future tax consequences attributable to the future utilization of existing tax net operating loss and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Comprehensive Income

Comprehensive income is defined as the change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. There is no difference between comprehensive income and reported income.

Statements of Cash Flows

For the purpose of the combined and consolidated statements of cash flows, Bois d’Arc Energy considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Earnings Per Share

Basic earnings per share is determined without the effect of any outstanding potentially dilutive stock options or other convertible securities and diluted earnings per share is determined with the effect of outstanding stock options and other convertible securities that are potentially dilutive. Bois d’Arc Energy converted to a corporation and issued shares of common stock in its initial public offering in May 2005. Basic and diluted earnings per share for the period from Inception (July 16, 2004) to December 31, 2004 and the year ended December 31, 2005 were determined based upon the Company’s assumption that the shares issued for the converted units were outstanding from Inception, as follows:

	Period From Inception
	(July 16, 2004)
	through December 31, 2004
					Per
			Units(1)		Unit(1)
	Income		(Shares)		(Share)
	(In thousands, except per unit amounts)
Basic Earnings Per Unit (Share):
Net Income	$	15,248		50,000	$	0.30
Diluted Earnings Per Unit (Share):
Net Income	$	15,248		50,000
Effect of Dilutive Securities:
Unit (Share) Grants and Options		—		485
Net Income Available to Unitholders (Shareholders) With Assumed Conversions	$	15,248		50,485	$	0.30

(1) LLC Units were converted to equivalent common shares as if the Company’s conversion to a corporation had occurred at Inception.

F-12

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended December 31, 2005
							Per
				Shares			Share
	Income			(Units)(1)			(Unit)(1)
	(In thousands, except per share amounts)
Basic Earnings Per Share (Unit):
Net Loss	$	(51,672	)		57,909		$	(0.89	)
Diluted Earnings Per Share (Unit):
Net Loss	$	(51,672	)		57,909
Effect of Dilutive Securities:
Stock (Unit) Grants and Options		—			—	(2)
Net Loss Available to Common Stockholders (Unitholders) With Assumed Conversions	$	(51,672	)		57,909		$	(0.89	)

(1)	LLC Units were converted to equivalent common shares as if the Company’s conversion to a corporation had occurred at Inception.
(2)	For the year ended December 31, 2005 the effect of stock grants and options would have been anti-dilutive to the net loss.

Asset Retirement Obligations

The Company adopted Statement of Financial Accounting Standards No. 143 (“SFAS 143”) “Accounting for Asset Retirement Obligations,” effective January 1, 2003. This statement requires that a liability is to be recognized in the period in which an asset retirement obligation (“ARO”) is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter, this liability is accreted up to the final retirement cost.

The adoption of SFAS 143 effective January 1, 2003 by the Company resulted in a cumulative effect adjustment to record (i) a $4.5 million decrease in the carrying value of oil and gas properties, (ii) a $1.2 million decrease in accumulated depreciation, depletion and amortization, (iii) a $2.6 million decrease in reserve for future abandonment, and (iv) a loss of $739,000, which was reflected as the cumulative effect of a change in accounting principle.

The following pro forma data summarizes net income for the year ended December 31, 2003 as if Bois d’Arc Energy had adopted the provisions of SFAS 143 on December 31, 2002, including its aggregate pro forma asset retirement obligations on that date of $17.8 million.

	Year Ended
	December 31,
	2003
	(In thousands)
Net income, as reported	$	51,929
Pro forma adjustments to reflect retroactive adoption of SFAS 143		739
Pro forma net income	$	52,668

F-13

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Bois d’Arc Energy’s primary asset retirement obligations relate to future plugging and abandonment expenses on its oil and gas properties and related facilities disposal. The following table summarizes the changes in Bois d’Arc Energy’s total estimated liability:

						Period from
				Period from		Inception
	Year Ended			January 1, 2004		(July 16, 2004)			Year Ended
	December 31,			to July 15,		to December 31,			December 31,
	2003			2004		2004			2005
	(In thousands)
Beginning asset retirement obligations	$	20,395		$	24,876	$	26,443		$	28,253
Cumulative effect adjustment		(2,560	)		—		—			—
New wells placed on production and changes in estimates		444			797		1,566			5,276
Acquisition liabilities assumed		6,324			—		—			—
Liabilities settled		(680	)		—		(591	)		(422	)
Accretion expense		953			770		835			1,927
Ending asset retirement obligations	$	24,876		$	26,443	$	28,253		$	35,034

New Accounting Standards

On December 16, 2004, the Financial Accounting Standards Board (“FASB”) issued Statement 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”) that requires compensation costs related to share-based payment transactions (issuance of stock options and restricted stock) to be recognized in the financial statements. With limited exceptions, the amount of compensation cost is to be measured based on the grant date fair value of the equity or liability instruments issued. Compensation cost is recognized over the period that an employee provides service in exchange for the award. Statement 123R replaces SFAS 123 “Accounting for Stock-Based Compensation” and supersedes APB 25. SFAS 123R is effective for the first reporting period after June 15, 2005. Entities that use thefair-value-based method for either recognition or disclosure under SFAS 123 are required to apply SFAS 123R using a modified version of prospective application whereby the entity is required to record compensation expense for all awards it grants after the date of adoption and the unvested portion of previously granted awards that remain outstanding at the date of adoption. The Company used a fair value-based measure in connection with its incentive plan awards on formation. Therefore, SFAS 123R will not have a significant impact on the Company.

(3)   Acquisition

In October 2003, the Bois d’Arc Energy Predecessors acquired an additional working interest in the Ship Shoal 113 Unit for $4.6 million.

(4)   Bank Credit Facility

The Company entered into a $175.0 million bank credit facility with The Bank of Nova Scotia and several other banks on May 11, 2005. Borrowings under the credit facility are limited to a borrowing base which is re-determined semi-annually based on the banks’ estimates of the future net cash flows of the Company’s oil and natural gas properties. The determination of the borrowing base is at the sole discretion of the administrative agent and the bank group. As of December 31, 2005, the borrowing base was $100.0 million. The credit facility matures on May 11, 2009. Borrowings under the credit facility bear interest at the Company’s option at either (1) LIBOR plus a margin that varies from 1.25% to 2.0% depending upon the ratio of the amounts outstanding to the borrowing

F-14

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

base or (2) the base rate (which is the higher of the prime rate or the federal funds rate) plus a margin that varies from 0% to 0.75% depending upon the ratio of the amounts outstanding to the borrowing base. A commitment fee ranging from 0.375% to 0.50% (depending upon the ratio of the amounts outstanding to the borrowing base) is payable on the unused borrowing base.

Indebtedness under the credit facility is secured by substantially all of the Company’s and its subsidiaries’ assets, and all of the Company’s subsidiaries are guarantors of the indebtedness. The credit facility contains covenants that restrict the payment of cash dividends, borrowings, sales of assets, loans to others, capital expenditures, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders and requires the Company to maintain a ratio of current assets to current liabilities ofone-to-one and a ratio of indebtedness to earnings before interest, taxes, depreciation, depletion, and amortization, exploration and impairment expense of 2.5 to one. The credit facility requires the Company to maintain a lien in favor of the lenders on properties representing at least 80% of the total value of the Company’s proved reserves (which amount increases to 95% upon the occurrence of an event of default). The Company was in compliance with these covenants as of December 31, 2005.

(5)   Payable to Comstock Resources

In connection with the formation of the Company, Comstock provided a revolving line of credit to Bois d’Arc Energy with a maximum outstanding amount of $200.0 million. Approximately $152.4 million was borrowed on the line of credit to repay the liabilities assigned to the Company at its formation, including the $83.2 million payable to Comstock, $13.5 million of advances made by Comstock Offshore and Bois d’Arc under the joint exploration venture and $55.7 million to refinance the bank loan and other obligations of the Bois d’Arc Participants. Borrowings under the credit facility bore interest at the Company’s option at either LIBOR plus 2% or the base rate (which is the higher of the prime rate or the federal funds rate) plus 0.75%. Interest expense of $2.7 million and $2.7 million was charged by Comstock under the credit facility during the period from Inception to December 31, 2004 and in 2005, respectively. On May 11, 2005 the Company repaid the outstanding balance of $158.0 million under the Comstock provided credit facility with proceeds from the initial public offering and borrowings under its bank credit facility.

Prior to the formation of Bois d’Arc Energy, Comstock made advances to Comstock Offshore to fund Comstock Offshore’s acquisition, development and exploration activities. There were no repayment terms established by Comstock for its wholly-owned subsidiary. Interest expense has been included in the accompanying financial statements on the advances made to Comstock Offshore based on Comstock’s average interest costs under its bank credit facility. The accompanying financial statements include interest expense of $9.0 million and $4.2 million for the year ended December 31, 2003 and the period from January 1, 2004 to July 15, 2004, respectively, related to the advances from Comstock to Comstock Offshore. The payable to Comstock was refinanced in its entirety on the date of the Company’s formation by the contribution of $262.5 million to the equity of the Company and by $83.2 million in borrowings under the Company’s $200.0 million credit facility provided by Comstock, which matures on April 1, 2006.

(6)   Stockholders’ and Members’ Equity

The authorized capital stock of Bois d’Arc Energy consists of 100 million shares of common stock, $.01 par value per share (the “Common Stock”) and 10 million shares of preferred stock, $.01 par value per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors. There were no shares of preferred stock outstanding.

While it was organized as a limited liability company, Bois d’Arc Energy had three classes of membership units — class A, class B and class C units. Class A units represented an interest in the capital of the Company but

F-15

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

no interest in the profits of the Company and had voting rights. Class B units represented an interest in the capital and profits of the Company and had no voting or other decision-making rights except as required by applicable law. Class C units represented an interest only in the profits of the Company and had no voting or other decision-making rights except as required by applicable law. In connection with the Company’s conversion from a limited liability company to a corporation, all outstanding limited liability units were converted into shares of Common Stock except for the Class A units which were redeemed at a price of $1 per unit. The Company issued 50,000,000 shares of Common Stock for all of the Class B units and 2,145,000 restricted shares of Common Stock for all of the Class C units.

On May 11, 2005, the Company completed an initial public offering of 13,500,000 shares of Common Stock at $13.00 per share to the public. The Company sold 12,000,000 shares of Common Stock and received net proceeds of $145.1 million and a selling stockholder sold 1,500,000 shares of which the Company received no proceeds.

(7)   Long Term Incentive Plan

On July 16, 2004, the Company’s unit holders approved the 2004 Long-term Incentive Plan for management including officers, directors, employees and consultants. The plan was amended and restated on May 11, 2005 to reflect the Company’s conversion to a corporation (as restated, the “Incentive Plan”). The Incentive Plan authorizes the grant of non-qualified options to purchase shares of common stock and the grant of restricted shares of Common Stock. The options under the Incentive Plan have contractual lives of up to ten years and become exercisable after lapses in vesting periods ranging from one to five years from the grant date. The Incentive Plan provides that awards in the aggregate cannot exceed 11% of the total outstanding shares of Common Stock of the Company. The initial awards of options to purchase Class B units under the Incentive Plan were each converted to options to purchase one share of Common Stock in connection with the Company’s conversion to a corporation.

The following table summarizes information about the Incentive Plan stock options outstanding at December 31, 2005:

Number of						Number of
Shares				Weighted Average		Shares
Outstanding		Exercise Price		Remaining Life		Exercisable
		(Years)
	2,800,000	$	6.00		8.5		560,000
	62,500	$	12.00		9.4		—
	25,000	$	12.80		4.4		—
	217,500	$	15.55		9.6		—
	3,105,000				8.6		560,000

The following table summarizes stock option activity under the Incentive Plan:

				Weighted
				Average
	Number			Exercise
	of Shares		Exercise Price	Price
Initial Grants		2,800,000	$6.00	$6.00
Outstanding at December 31, 2004		2,800,000	$6.00	$6.00
Granted		305,000	$12.00 to $15.55	$14.60
Outstanding at December 31, 2005		3,105,000	$6.00 to $15.55	$6.84
Exercisable at December 31, 2005		560,000	$6.00	$6.00

F-16

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The value of the initial grants of options to purchase class B units was determined to be $4.55 per option using the Black-Scholes option pricing model and the following assumptions: exercise price of $6.00 per unit; fair value on the date of issuance of $8.42 per unit; dividend yield of 0%; expected volatility of 29.8%; risk-free interest rate of 4.0% and average expected life of 7.5 years. The fair value of the 2005 option grants was estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions: risk-free interest rate of 4.3%; expected life of 8.9 years; expected volatility factor of 37.8; and 0% dividend yield. The estimated weighted average fair value of options to purchase one share of common stock issued under the Company’s incentive plans was $4.55 in 2004 and $7.63 in 2005. Compensation expense recognized for stock options for the period from Inception through December 31, 2004 and for the year ended December 31, 2005 was $1.2 million and $2.8 million, respectively.

Also under the Incentive Plan, certain officers, managerial employees and consultants were granted a right to receive Class C units without cost to the recipient. The restrictions on the Class C units lapsed over a five year period. The Class C units were entitled to participate in the appreciation of the Company’s value and were convertible to a maximum of one-half of a Class B unit. The initial grants of Class C units under the Incentive Plan were converted to restricted shares of Common Stock on a 2 for 1 basis upon the Company’s conversion to a corporation. Restricted stock grants were made for 10,000 shares in 2005. The weighted average fair value per share of the restricted stock grants were $6.80 and $12.00 in 2004 and 2005, respectively. In the aggregate, 2,155,000 restricted stock grants have been awarded under the Incentive Plans. As of December 31, 2005, 429,000 shares of such awards were vested. A provision for the restricted stock grants is made over the related vesting period. Compensation expense recognized for restricted stock grants for the period from Inception through December 31, 2004 and for the year ended December 31, 2005 was $1.3 million and $2.9 million, respectively.

(8)   Retirement Plan

Bois d’Arc Energy has a 401(k) profit sharing plan which covers all of its employees. At its discretion, the Company may match a certain percentage of the employees’ contributions to the plan. The matching percentage is determined annually by the Board of Directors. Bois d’Arc Energy’s matching contributions to the plan were $8,000 and $32,000 in 2004 and 2005, respectively.

(9)   Commitments and Contingencies

Guarantees of Comstock Debt

In consideration for the $200.0 million credit facility provided by Comstock prior to the Company’s initial public offering, Bois d’Arc Energy and each of its subsidiaries agreed to become guarantors of Comstock’s 67/8% senior notes due 2012. Bois d’Arc Energy was also a guarantor of and had agreed to pledge substantially all of its assets with respect to Comstock’s $400.0 million bank credit facility. Following the Company’s initial public offering in May 2005, the Comstock provided credit facility was cancelled and Bois d’Arc Energy was released as a guarantor of Comstock’s debt.

Contingencies

From time to time, Bois d’Arc Energy is involved in certain litigation that arises in the normal course of its operations. The Company does not believe the resolution of these matters will have a material effect on the Company’s financial position or results of operations.

F-17

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Lease Commitments

The Company rents office space under a noncancelable lease that expires on April 30, 2012. Rent expense for 2004 and 2005 was $88,000 and $286,000, respectively. Minimum future payments under the lease are as follows:

	(In thousands)
2006	$	377
2007		383
2008		388
2009		402
2010		412
Thereafter		560
	$	2,522

(10)   Related Party Transactions

An entity owned by the spouse of Wayne L. Laufer, the Company’s chief executive officer and a director, provided accounting services to Bois d’Arc under a service agreement. Bois d’Arc paid this entity $688,000 and $494,000 for accounting services in 2003 and 2004, respectively. In connection with the formation of Bois d’Arc Energy, this agreement was terminated which resulted in a termination fee of $1.2 million that is payable in monthly installments over a two year period that commenced in October 2004. Subsequent to the formation of Bois d’Arc Energy, this entity performed services for the Company under a new consulting agreement. The Company paid $128,000 for such services in 2005.

In July 2004 Bois d’Arc Energy entered into a service agreement with Comstock pursuant to which Comstock provided accounting services for $240,000 annually. This agreement was subsequently modified in July 2005 to reduce the fees paid to Comstock to $60,000 annually. The Company paid Comstock $120,000 and $150,000 in 2004 and 2005, respectively under this service agreement.

(11)   Oil and Gas Producing Activities

Set forth below is certain information regarding the aggregate capitalized costs of oil and gas properties and costs incurred for oil and gas property acquisition, development and exploration activities:

Capitalized Costs

	As of December 31,
	2004			2005
	(In thousands)
Proved properties	$	735,630		$	920,725
Unproved properties		8,566			13,533
Accumulated depreciation, deletion and amortization		(233,243	)		(274,434	)
	$	510,953		$	659,824

F-18

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Costs Incurred

			Period from		Period from
			January 1,		Inception (July 16,
	Year Ended		2004		2004) to		Year Ended
	December 31,		to July 15,		December 31,		December 31,
	2003		2004		2004		2005
	(In thousands)
Property acquisitions:
Proved properties	$	5,222	$	726	$	—	$	—
Unproved properties		1,438		2,049		120		5,159
Development costs		47,620		51,140		30,865		124,139
Exploration costs		51,452		31,298		30,261		77,750
	$	105,732	$	85,213	$	61,246	$	207,048

(12)   Exploration Venture

On July 31, 2001, Comstock Offshore entered into an exploration agreement with Bois d’Arc, which replaced an exploration agreement entered into on December 8, 1997 between the parties. The 2001 exploration agreement continued a joint exploration program between Comstock Offshore and Bois d’Arc covering the state coastal waters of Louisiana and Texas and corresponding federal offshore waters in the Gulf of Mexico. Under the joint exploration venture, Bois d’Arc generated exploration prospects in the Gulf of Mexico utilizing3-D seismic data and its extensive geological expertise in the region. Comstock Offshore advanced 100% of the funds for the acquisition of3-D seismic data and leases. The amounts advanced by Comstock Offshore for leasehold and seismic data acquisitions were recorded as unevaluated properties and as exploration expense as the reimbursements or repayment of such advances by Bois d’Arc were not unconditional. The collection of the advances was subject to a drillable prospect being developed that Comstock Offshore, Bois d’Arc or other third parties would agree to drill. For each drillable prospect generated under the exploration venture, Comstock Offshore was reimbursed for all previously advanced costs and was entitled to a 40% non-promoted working interest in the prospect. The remaining interest in the prospect was retained by Bois d’Arc. Bois d’Arc sold a portion of the prospect interest to unrelated entities. In connection with the formation of Bois d’Arc Energy, the exploration agreement was terminated and Comstock Offshore and Bois d’Arc were reimbursed $12.7 million and $0.8 million, respectively, for advances made for undrilled prospects.

Under the exploration agreement, the principals of Bois d’Arc had the opportunity to earn warrants to purchase up to 1,620,000 shares of common stock of Comstock. Warrants to purchase 60,000 shares were earned for each prospect that resulted in a successful discovery. The exercise price on the warrants was determined based on the current market price for Comstock’s common stock on a semi-annual basis each year that the venture was in existence. The principals of Bois d’Arc earned warrants under the exploration agreement to purchase an aggregate of 900,000 and 240,000 shares of Comstock’s common stock in 2003 and the period from January 1, 2004 to July 15, 2004, respectively. The value of the warrants based on the Black-Scholes option pricing model was $8.36 per share or an aggregate of $7.5 million in 2003 and $9.69 per share or $2.3 million for the period from January 1, 2004 to July 15, 2004. Such amounts were capitalized by Comstock Offshore as a cost of oil and gas properties. Comstock Offshore included the value of these warrants in its payable to parent company.

(13)   Income Taxes

Bois d’Arc Energy became a taxable entity as a result of its conversion from a limited liability company to a corporation on May 10, 2005. While Bois d’Arc Energy was a limited liability company, taxable income passed through to its unit owners. The Bois d’Arc Energy Predecessors were either individuals, partnerships or limited

F-19

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

liability companies that pass through their taxable income to their owners. Accordingly, provision for federal and state corporate income taxes has been made only for the operations of Bois d’Arc Energy from May 10, 2005 through December 31, 2005 in the accompanying consolidated financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon its conversion to a corporation on May 10, 2005, the Company established a $108.2 million provision for deferred income taxes.

The following is an analysis of the consolidated income tax expense for the period from May 10, 2005 to December 31, 2005:

	(In thousands)
Current	$	2,552
Deferred		123,256
	$	125,808

In 2005, Bois d’Arc Energy’s effective tax rate of 169.7% was different from the amount computed by applying the statutory federal income tax rate to income before provision for income taxes. The sources and tax effects of these differences are as follows:

	(In thousands)
Income tax (provision) at the federal statutory rate of 35%	$	25,948
Benefit for period not taxed as an entity		(9,039	)
Deferred taxes recognized upon conversion to a taxable entity		108,199
Nondeductible stock-based compensation		700
	$	125,808

Excluding the one time charge of $108.2 million recognized upon the conversion to a taxable entity, Bois d’Arc’s effective tax rate was 36% in 2005, which differed from the statutory rate of 35% because of state income taxes and also due to permanent book tax differences relating to stock-based compensation.

Pro forma income tax expense represents the tax effects that would have been reported had the Company been subject to U.S. federal and state income taxes as a corporation for all periods presented. Pro forma expenses are based upon the statutory income tax rates and adjustments to income for estimated permanent differences occurring during the period. Actual rates and expenses could have differed had the Company been subject to U.S. federal and state income taxes for all periods presented. Therefore, the pro forma amounts are for informational purposes only and are intended to be indicative of the results of operations had the Company been subject to U.S. federal and state income taxes for all periods presented.

The following table presents the computation of the pro forma income tax expense:

				Period from			Period from
				January 1,			Inception (July 16,
	Year Ended			2004			2004) to			Year Ended
	December 31,			to July 15,			December 31,			December 31,
	2003			2004			2004			2005
	(In thousands)
Income before income taxes	$	52,668		$	23,773		$	15,248		$	74,136
Effective pro forma income tax rate		35	%		35	%		38	%		36	%
Pro forma income tax expense	$	18,434		$	8,321		$	5,807		$	26,914

F-20

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The tax effects of significant temporary differences representing the net deferred tax liability at December 31, 2005 was as follows:

	(In thousands)
Net deferred tax assets (liabilities):
Property and equipment	$	(125,073	)
Stock options		1,355
Other assets		462
	$	(123,256	)

(14)   Supplementary Quarterly Financial Data (Unaudited)

2004 — 

	Combined Bois d’Arc Energy
	Predecessors						Bois d’Arc Energy
	First		Second		Total		Third			Fourth			Total
	(In thousands, except per share amounts)
Total oil and gas sales	$	29,908	$	40,433	$	70,341	$	37,358		$	35,363		$	72,721
Income from operations	$	9,154	$	18,997	$	28,151	$	10,393		$	9,284		$	19,677
Net income	$	7,031	$	16,742	$	23,773	$	7,635		$	7,613		$	15,248
Pro forma net income as if converted to a corporation	$	4,570	$	10,882	$	15,452	$	4,730		$	4,711		$	9,441
Net income per share (unit):
Basic							$	0.15(1	)	$	0.15(1	)	$	0.30(1	)
Diluted							$	0.15(1	)	$	0.15(1	)	$	0.30(1	)
Pro forma net income per share (unit):
Basic							$	0.09(1	)	$	0.09(1	)	$	0.19(1	)
Diluted							$	0.09(1	)	$	0.09(1	)	$	0.19(1	)

2005 — 

	Bois d’Arc Energy
	First			Second			Third		Fourth		Total
	(In thousands, except per share amounts)
Total oil and gas sales	$	43,476		$	48,685		$	43,434	$	48,841	$	184,436
Income from operations	$	18,785		$	20,713		$	21,087	$	17,193	$	77,778
Net income	$	17,062		$	(92,441	)(2)	$	13,269	$	10,438	$	(51,672	)
Pro forma net income as if converted to a corporation	$	10,974		$	12,541		$	13,269	$	10,438	$	47,222
Net income per share (unit):
Basic	$	0.34	(1)	$	(1.62	)	$	0.21	$	0.17	$	(0.89	)
Diluted	$	0.33	(1)	$	(1.62	)(3)	$	0.21	$	0.16	$	(0.89	)(3)
Pro forma net income per share (unit):
Basic	$	0.21	(1)	$	0.22		$	0.21	$	0.17	$	0.82
Diluted	$	0.21	(1)	$	0.21		$	0.21	$	0.16	$	0.79

(1)	LLC units were converted to equivalent common shares as if the Company’s conversion to a corporation had occurred at inception.
(2)	Includes $108.2 million one time tax provision upon conversion to a taxable entity.
(3)	Basic and diluted are the same due to the net loss.

F-21

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(15)   Oil and Gas Reserves Information (Unaudited)

Set forth below is a summary of the changes in Bois d’Arc Energy’s net quantities of crude oil and natural gas reserves for each of the year ended December 31, 2003, the period from January 1, 2004 to July 15, 2004, the period from July 16, 2004 to December 31, 2004 and the year ended December 31, 2005:

							Period from						Period from Inception
	Year Ended						January 1, 2004 to						(July 16, 2004) to						Year Ended
	December 31,						July 15,						December 31,						December 31,
	2003						2004						2004						2005
	Oil			Gas			Oil			Gas			Oil			Gas			Oil			Gas
	(MBbls)			(MMcf)			(MBbls)			(MMcf)			(MBbls)			(MMcf)			(MBbls)			(MMcf)
Proved Reserves:
Beginning of year		18,350			143,157			19,518			204,744			18,436			183,887			18,732			192,935
Revisions of previous estimates		(1,620	)		(2,024	)		(845	)		(39,298	)		(623	)		2,880			(969	)		(22,043	)
Extensions and discoveries		2,919			70,193			595			24,708			1,698			12,076			2,922			49,990
Purchases of minerals in place		1,330			8,649			—			—			—			—			—			—
Production		(1,461	)		(15,231	)		(832	)		(6,267	)		(779	)		(5,908	)		(1,155	)		(14,896	)
End of year		19,518			204,744			18,436			183,887			18,732			192,935			19,530			205,986
Proved Developed Reserves:
Beginning of year		12,374			96,320			14,185			152,915			14,214			161,297			14,278			167,730
End of year		14,185			152,915			14,214			161,297			14,278			167,730			15,316			175,838

The following table sets forth the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2003, 2004 and 2005:

	2003			2004			2005
	(In thousands)
Cash Flows Relating to Proved Reserves:
Future Cash Flows	$	1,911,143		$	1,949,678		$	3,234,675
Future Costs:
Production		(239,103	)		(331,887	)		(313,342	)
Development and Abandonment		(135,709	)		(124,121	)		(169,238	)
Income taxes		—			—			(920,987	)
Future Net Cash Flows		1,536,331			1,493,670			1,831,108
10% Discount Factor		(472,282	)		(496,946	)		(548,683	)
Standardized Measure of Discounted Future
Net Cash Flows	$	1,064,049		$	996,724		$	1,282,425

Income taxes have been deducted only in 2005 because the Bois d’Arc Energy Predecessors are either individuals or partnerships or limited liability companies that pass through their taxable income to their owners and Bois d’Arc Energy was organized as a limited liability company prior to its conversion to a corporation in May 2005.

F-22

BOIS d’ARC ENERGY, INC.

BOIS d’ARC ENERGY PREDECESSORS

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table sets forth the changes in the standardized measure of discounted future net cash flows relating to proved reserves for the year ended December 31, 2003, the period from January 1, 2004 to July 15, 2004, the period from July 16, 2004 to December 31, 2004 and for the year ended December 31, 2005:

							Period from
				Period from			Inception (July 16,
	Year Ended			January 1, 2004			2004) to			Year Ended
	December 31,			to July 15,			December 31,			December 31,
	2003			2004			2004			2005
	(In thousands)
Standardized Measure, Beginning of Period	$	655,370		$	1,064,049		$	993,124		$	996,724
Net Change in Sales Price, Net of Production Costs		116,656			15,659			29,256			687,692
Development Costs Incurred During the Period Which Were Previously Estimated		28,508			50,354			19,523			28,319
Revisions of Quantity Estimates		(39,371	)		(134,727	)		(3,119	)		(162,481	)
Accretion of Discount		65,537			53,203			49,656			99,672
Changes in Future Development and Abandonment Costs		(18,269	)		(22,097	)		(11,274	)		(22,674	)
Extensions and Discoveries		319,652			90,215			90,093			475,944
Purchases of Reserves in Place		56,311			—			—			—
Sales, Net of Production Costs		(111,160	)		(55,108	)		(56,119	)		(147,347	)
Changes in Timing of Production		(9,185	)		(68,424	)		(114,416	)		(27,815	)
Net Changes in Income Taxes		—			—			—			(645,609	)
Standardized Measure, End of Period	$	1,064,049		$	993,124		$	996,724		$	1,282,425

The estimates of proved oil and gas reserves utilized in the preparation of the financial statements were estimated by Lee Keeling and Associates, Inc., independent petroleum consultants, in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve reports be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual agreement. Substantially all of Bois d’Arc Energy’s reserves are located offshore in the federal and state waters of the Gulf of Mexico.

Future cash inflows are calculated by applying year-end prices adjusted for transportation and other charges to the year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements in existence at year-end.

Bois d’Arc Energy’s average year-end prices used in the reserve estimates were as follows:

	2003		2004		2005
Crude Oil (Per Barrel)	$	31.50	$	42.14	$	57.92
Natural Gas (Per Mcf)	$	6.33	$	6.01	$	10.21

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

F-23

EXHIBIT INDEX

Exhibit No.			Description
	2	.1	Contribution Agreement, dated as of July 16, 2004, by and among Bois d’Arc Energy, LLC, Bois d’Arc Properties, LP, Bois d’Arc Resources, Ltd., Wayne L. Laufer, Gary W. Blackie, Haro Investments LLC, Comstock Offshore, LLC, Comstock Resources, Inc. and such other persons listed on the signature pages thereto (incorporated by reference to Exhibit 10.2 to Comstock Resources, Inc.’s Quarterly Report onForm 10-Q for the quarter ended June 30, 2004 (FileNo. 0-16741)).
	3	.1	Articles of Incorporation (incorporated by reference to Exhibit 3.1 to our Quarterly Report onForm 10-Q for the quarter ended March 31, 2005).
	3	.2	Bylaws (incorporated by reference to Exhibit 3.5 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	3	.3	Articles of Organization of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.1 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	3	.4	Amended and Restated Operating Agreement, dated as of August 23, 2004 to be effective July 16, 2004, of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.2 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	3	.5	First Amendment, dated as of September 29, 2004, to the Amended and Restated Operating Agreement of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.3 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	3	.6	Second Amendment, dated as of January 26, 2005, to the Amended and Restated Operating Agreement of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.6 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	3	.7	Third Amendment, effective as of July 16, 2004, to the Amended and Restated Operating Agreement of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.7 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	3	.8	Fourth Amendment, dated as of April 13, 2005, to the Amended and Restated Operating Agreement of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.8 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	3	.9	Fifth Amendment, effective as of July 16, 2004, to the Amended and Restated Operating Agreement of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.9 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	4	.1	Specimen Stock Certificate of Common Stock (incorporated by reference to Exhibit 4.3 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	10	.1#	Amended and Restated Long-Term Incentive Plan of Bois d’Arc Energy, Inc. (incorporated by reference to Exhibit 10.2 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	10	.2#	Form of Option Agreement under the Bois d’Arc Energy, Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to our Quarterly Report onForm 10-Q for the quarter ended March 31, 2005).
	10	.3#	Form of Restricted Stock Agreement under the Bois d’Arc Energy, Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 99.2 to our Quarterly Report onForm 10-Q for the quarter ended March 31, 2005).
	10	.4#	Employment Agreement, dated as of July 16, 2004, between Bois d’Arc Energy, LLC and Gary W. Blackie (incorporated by reference to Exhibit 10.3 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	10	.5#	Employment Agreement, dated as of July 16, 2004, between Bois d’Arc Energy, LLC and Wayne L. Laufer (incorporated by reference to Exhibit 10.4 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	10	.6	Credit Agreement dated May 11, 2005 between Bois d’Arc Energy, Inc., and the Bank of Nova Scotia as Administrative Agent and Issuing Bank, Calyon New York Branch, as Syndication Agent, AmSouth Bank as Documentation Agent and the other lenders (incorporated by reference to Exhibit 10.1 to our Quarterly Report onForm 10-Q for the quarter ended March 31, 2005).

Exhibit No.			Description
	10	.7	Loan Agreement, dated as of July 16, 2004, by and between Comstock Resources, Inc., as lender, and Bois d’Arc Energy, LLC, Bois d’Arc Properties, LP, and Bois d’Arc Offshore, Ltd., as borrower (incorporated reference to Exhibit 10.4 to Comstock Resources, Inc.’s Quarterly Report onForm 10-Q for the quarter ended June 30, 2004 (FileNo. 0-16741)).
	10	.8	Services Agreement, dated as of July 16, 2004, between Comstock Resources, Inc. and Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 10.3 to Comstock Resources, Inc.’s Quarterly Report onForm 10-Q for the quarter ended June 30, 2004 (File No.0-16741)).
	10	.9	Lease Agreement dated December 1, 2004 between Texas Tower Limited and Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 10.8 to our Registration Statement onForm S-1 (FileNo. 333-119511)).
	21	*	List of Subsidiaries.
	23	.1*	Consent of Ernst & Young LLP.
	23	.2*	Consent of Lee Keeling and Associates, Inc.
	31	.1*	Chief Executive Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31	.2*	Chief Financial Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32	.1+	Chief Executive Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
	32	.2+	Chief Financial Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.

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