Bois D Arc Energy 10K 2007 Annual report

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

FORM 10-K


(Mark One)

þ		ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2007
		OR
o		TRANSITION REPORT PURSUANT TO SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission FileNo. 001-32494

BOIS d’ARC ENERGY, INC.

(Exact name of registrant as specified in its charter)


NEVADA		20-1268553
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		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		New York Stock Exchange
(Title of class)		(Name of exchange on which registered)

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes 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 and reference in Part III of thisForm 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer and smaller reporting Company. See definition of large accelerated filer “accelerated filer” and “smaller reporting Company” inRule 12b-2 of the Exchange Act. (Check one):


Large accelerated filero		Accelerated filerþ		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

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

As of February 28, 2008, there were 66,441,003 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 29, 2007 (the last business day of the registrant’s most recently completed second fiscal quarter), was $304.2 million.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2008 Annual Meeting of Stockholders to be held
May 22, 2008 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, 2007

CONTENTS


Item		Page

PART I
	Cautionary Note Regarding Forwarding Looking Statements		2
	Definitions		3
1. and 2.	Business and Properties		6
1A.	Risk Factors		21
1B.	Unresolved Staff Comments		32
3.	Legal Proceedings		32
4.	Submission of Matters to a Vote of Security Holders		32

PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		33
6.	Selected Financial Data		35
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		36
7A.	Quantitative and Qualitative Disclosures About Market Risk		47
8.	Financial Statements and Supplementary Data		47
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		48
9A.	Controls and Procedures		48
9B.	Other Information		50

PART III
10.	Directors and Executive Officers of the Registrant		50
11.	Executive Compensation		50
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		50
13.	Certain Relationships, Related Transactions, and Director Independence		50
14.	Principal Accountant Fees and Services		50

PART IV
15.	Exhibits and Financial Statement Schedules		51
Fourth Amendment to Credit Agreement
Consulting Agreement
List of Subsidiaries
Consent of Ernst & Young LLP
Consent of Lee Keeling and Associates, Inc.
CEO Certification under Section 302
CFO Certification under Section 302
CEO Certification under Section 906
CFO Certification under Section 906

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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


	•	amount and timing of future production of oil and natural gas;
	•	the availability of exploration and development opportunities;
	•	amount, nature and timing of capital expenditures;
	•	the number of anticipated wells to be drilled after the date hereof;
	•	our financial or operating results;
	•	our cash flow and anticipated liquidity;
	•	operating costs including lease operating expenses, administrative costs and other expenses;
	•	finding and development costs;
	•	our business strategy; and
	•	other plans and objectives for future operations.

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


	•	the risks described in the “Risk Factors” and elsewhere in this report;
	•	the volatility of prices and supply of, and demand for, oil and natural gas;
	•	the timing and success of our drilling activities;
	•	the numerous uncertainties inherent in estimating quantities of oil and natural gas reserves and actual future production rates and associated costs;
	•	our ability to successfully identify, execute or effectively integrate future acquisitions;
	•	the usual hazards associated with the oil and natural gas industry, including fires, well blowouts, pipe failure, spills, explosions and other unforeseen hazards;
	•	our ability to effectively market our oil and natural gas;
	•	the availability of rigs, equipment, supplies and personnel;
	•	our ability to discover or acquire additional reserves;
	•	our ability to satisfy future capital requirements;
	•	changes in regulatory requirements;
	•	general economic and competitive conditions;
	•	our ability to retain key members of our senior management and key employees; and
	•	hostilities in the Middle East and other sustained military campaigns and acts of terrorism or sabotage.

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.

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

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

“MBbls”means one thousand barrels of oil.

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

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

“Mcfe”means 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 or 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 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%. Although PV 10 Value is not a financial measure calculated in accordance with GAAP, management believes that the presentation of PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and its current tax structure. We use this measure when assessing the potential return on investment related to our oil and gas properties. Because many factors that are unique to any given company affect the amount of estimated future income taxes, the use of a pre-tax measure is helpful to investors when comparing companies in our industry.

“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 mineral owner’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.

PART I

ITEMS 1. and 2. BUSINESS AND PROPERTIES

General

Bois d’Arc Energy, Inc. (“Bois d’Arc”) 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 oil and natural gas properties are estimated to have proved reserves of 398 Bcfe with an estimated PV 10 Value of $2.2 billion as of December 31, 2007 and a standardized measure of discounted future net cash flows of $1.8 billion. Our proved oil and natural gas reserve base is 63% natural gas and 37% proved developed on a Bcfe basis as of December 31, 2007, and we serve as operator for approximately 98% of our properties based on the PV 10 Value of the related proved reserves. In 2007 our daily production averaged 88 MMcf of natural gas and 4,578 barrels of oil or 116 MMcfe.

Strengths

Experienced Management and Technical Team. Our management and technical team has an average of 22 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 78 exploratory prospects as of December 31, 2007. 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. The majority 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 12% at December 31, 2007. 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, 2007, our exploration program has achieved an average drilling success rate of 70%, with 79 successful exploration wells out of a total of 113 drilled.

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 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. The majority 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 ten 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 68 out of 86 blocks on which we have bid, representing a 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, 2007, 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 2007, we spent approximately $46.5 million to drill eight development wells, 7.4 net to us, five of which were successful. In addition, we spent approximately $62.2 million in 2007 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 $250.0 million on development and exploration projects in 2008. We intend to primarily use operating cash flow to fund our drilling expenditures in 2008. We may also make additional property acquisitions that would require additional sources of funding. Such sources may include borrowings under our bank credit facility or issuances of our equity or debt securities.

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. Our Gulf of Mexico operations include properties located offshore of Louisiana in state and federal waters of the Gulf of Mexico. We own interests in 145 producing wells, 108.3 net to us. We operate 96% of our producing wells. Our production in 2007 averaged 88.2 MMcf of natural gas per day and 4,578 barrels of oil per day or 116 MMcfe per day. During 2007, we

spent $89.2 million drilling seven exploratory wells, 4.6 net to us and $46.5 million on eight development wells, 7.4 net to us. We also spent $62.2 million for production facilities, recompletions, abandonment and workovers, and $9.7 million on acquiring exploration acreage and seismic data during 2007. In 2008, we plan to spend approximately $250.0 million for our development and exploration activities. The following table summarizes the estimated proved oil and natural gas reserves for our ten largest operating areas as of December 31, 2007:


	Net Oil		Net Gas							PV 10
	(MBbls)		(MMcf)		MMcfe		%			Value⁽¹⁾			%
										(In thousands)

Ship Shoal 111 and the Ship Shoal 113 Unit		13,495		97,629		178,598		45	%	$	1,000,578			46	%
South Pelto 5 and South Timbalier 9, 11 and 16		833		28,216		33,215		8	%		174,915			8	%
South Pelto 22		1,125		19,782		26,532		7	%		165,702			8	%
Ship Shoal 66, 67, 68, 69 and South Pelto 1		3,217		6,685		25,985		7	%		165,840			8	%
Ship Shoal 97, 98, 99, 106, 107, 109 and 110		389		23,447		25,779		6	%		112,296			5	%
South Timbalier 75		683		12,366		16,465		4	%		92,537			4	%
South Timbalier 95, 96, 100, 101, 110 and 111		303		14,399		16,214		4	%		62,290			3	%
South Timbalier 34 and 50 and South Pelto 15		1,314		6,276		14,162		4	%		91,171			4	%
Ship Shoal 134, 135 and 146		4		12,720		12,743		3	%		56,270			3	%
Vermillion 87, 122 and 127		592		7,974		11,526		3	%		67,645			3	%
Other		2,677		20,640		36,706		9	%		207,304			8	%

Total		24,632		250,134		397,925		100	%		2,196,548			100	%

Discounted Future Income Taxes											(415,259	)

Standardized Measure of Discounted Future Net Cash Flows										$	1,781,289


(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 net cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.

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 957 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, acquired an additional 30% working interest in October 2003 and the remaining 20% interest during 2006. In 2005, we acquired the adjacent Ship Shoal block 111 together with an existing production platform. Since 2003 we have drilled 22 wells (20.7 net to us) in this area. We operate the four production platforms and the 36 producing wells (35.7 net to us) comprising these properties. Production from these properties net to our interest averaged 22.9 MMcf of natural gas per day and 1,856 barrels of oil per day, or 34.0 MMcfe per day, during December 2007.

South Pelto 5 and South Timbalier 9, 11, 16

We own interests in 15 producing wells, 10.6 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 19 wells, including redrills of existing wells (13.4 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 8.3 MMcf of natural gas per day and 328 barrels of oil per day, or 10.3 MMcfe per day, during December 2007.

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 have subsequently drilled four wells (2.5 net to us). 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 15.8 MMcf of natural gas per day and 370 barrels of oil per day, or 18.0 MMcfe per day, during December 2007.

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 21 wells (13.3 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. These wells are connected to four production platforms and share common oil terminal facilities. Production from these properties net to our interest averaged 406 barrels of oil per day during December 2007.

Ship Shoal 97, 98, 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 eleven successful wells (8.4 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 10.4 MMcf of natural gas per day and 121 barrels of oil per day, or 11.1 MMcfe per day, during December 2007.

South Timbalier 75

South Timbalier 75 is located in federal waters having a water depth of 63 feet, offshore of Terrebonne Parish, Louisiana. We acquired our 75% working interest position in South Timbalier block 75 by virtue of a farm-in from another offshore operator. We subsequently drilled three wells (2.6 net) with nine productive sands occurring at depths from 14,000 to 17,600 feet and installed a production platform and sales facilities for these wells. Production from the block net to our interest averaged 2.2 MMcf of natural gas per day and 249 barrels of oil per day, or 3.6 MMcfe per day, during December 2007.

South Timbalier 95, 96, 100, 101, 110 and 111

South Timbalier blocks 95, 96, 100, 101, 110, and 111 are located in federal waters with water depths from 60 to 63 feet, offshore of Terrebone Parish, Louisiana. We own and operate four producing wells (4.0 net) that share a common production infrastructure. These wells produce from four productive sands occurring at depths from 4,600 to 12,000 feet. Production from these properties net to our interest averaged 3.6 MMcf of natural gas per day and 71 barrels of oil per day, or 4.0 MMcfe per day, during December 2007.

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 ten producing wells (7.3 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 1.0 MMcf of natural gas per day and 125 barrels of oil per day, or 1.8 MMcfe per day, during December 2007.

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 federal lease sales. 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 feet. Our production from these properties net to our interest averaged 2.9 MMcf of natural gas per day and 7 barrels of oil per day, or 3.0 MMcfe per day, during December 2007.

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 3.7 MMcf of natural gas per day and 202 barrels of oil per day, or 4.9 MMcfe per day, during December 2007.

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, 2007:


	Oil		Gas		Total
	(MBbls)		(MMcf)		(MMcfe)		PV 10 Value⁽¹⁾
							(In thousands)

Proved Developed Producing		8,459		79,595		130,347	$	778,214
Proved Developed Non-producing		8,931		109,654		163,243		919,026
Proved Undeveloped		7,242		60,885		104,335		499,308

Total Proved		24,632		250,134		397,925		2,196,548

Discounted Future Income Taxes								(415,259	)

Standardized Measure of Discounted Future Net Cash Flows⁽¹⁾							$	1,781,289


(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, 2007. The market price for our oil production on December 31, 2007, after basis adjustments, was $94.64 per barrel. The market price received for our natural gas production on December 31, 2007, after basis adjustments, was $7.26 per Mcf.

We did not provide estimates of total proved oil and natural gas reserves during the years ended December 31, 2005, 2006 or 2007 to any federal authority or agency, other than the SEC.

Drilling Activity Summary

During the three-year period ended December 31, 2007, we drilled exploratory and development wells as set forth in the table below.


	2005				2006				2007
	Gross		Net		Gross		Net		Gross		Net

Exploratory Wells:
Oil		2		1.5		—		—		—		—
Gas		8		6.4		8		7.0		2		1.6
Dry		1		0.6		3		2.5		5		3.0

		11		8.5		11		9.5		7		4.6
Development Wells:
Oil		3		3.0		—		—		4		4.0
Gas		6		5.2		2		1.7		1		1.0
Dry		2		2.0		—		—		3		2.4

		11		10.2		2		1.7		8		7.4

Total Wells		22		18.7		13		11.2		15		12.0

Subsequent to December 31, 2007, we drilled two successful development wells (1.8 net to us) and one successful exploration well (0.8 net to us) and as of February 28, 2008 we had one well (0.8 net to us) that was 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, 2007:


	Oil				Gas
	Gross		Net		Gross		Net

Offshore:
Louisiana		15		13.7		9		6.4
Federal		46		30.5		75		57.7

Total		61		44.2		84		64.1

We operate 122 of the 145 producing wells presented in the above table. As of December 31, 2007, we owned interests in 21 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.

Acreage

The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2007. 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		6,660		5,574		1,399		1,399		8,059		6,973
Federal		231,271		170,920		150,202		149,152		381,473		320,072

Total		237,931		176,494		151,601		150,551		389,532		327,045

176,494 net acres or 54% percent of our total acreage is held by production. Our undeveloped leasehold acreage totaling 150,551 net acres expires as follows:


Expires in 2008	24	%
Expires in 2009	28	%
Expires in 2010	11	%
Expires in 2011	13	%
Expires in 2012	7	%
Expires in 2013	10	%
Expires in 2017	7	%

	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 49% of our 2007 natural gas sales were priced utilizing index prices and 51% were priced utilizing daily spot prices. Two subsidiaries of Shell Oil Company (Shell Trading (US) Company and Coral Resources LP) were our most significant purchasers of crude oil and natural gas, accounting for 89% of our total 2007 oil and gas sales. Shell Trading (US) Company was our most significant purchaser of crude oil in 2007, accounting for 31% of total oil and gas sales. Coral Energy Resources LP was our most significant purchaser of natural gas in 2007, accounting for approximately 58% of our total 2007 oil and gas sales. The loss of these customers would not have a material adverse effect on us as there is an available market for our crude oil and natural gas production from other purchasers.

Regulation

General. Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulation, as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members. The Federal Energy Regulatory Commission, or “FERC,” regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938, or “NGA,” and the Natural Gas Policy Act of 1978, or “NGPA.” In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting all “first sales” of natural gas, effective January 1, 1993, subject to the terms of any private contracts that may be in effect. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, in the future Congress could reenact price controls or enact other legislation with detrimental impact on many aspects of our business. Under the provisions of the Energy Policy Act of 2005 (the “2005 Act”), the NGA has been amended to prohibit any form of market manipulation with the purchase or sale of natural gas, and the FERC has issued new regulations that are intended to increase natural gas pricing transparency. The 2005 Act has also significantly increased the penalties for violations of the NGA.

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.

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; 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 price received from the sale of these products may be affected by the cost of transporting the products to market.

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

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

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

Environmental regulations. We are subject to stringent federal, state and local laws. These laws, among other things, govern the issuance of permits to conduct exploration, drilling and production operations, the amounts and types of materials that may be released into the environment, the discharge

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

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

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

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

Our operations are also subject to the Clean Air Act, or “CAA,” and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the

gradual imposition of certain pollution control requirements with respect to air emissions from our operations. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

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

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

Executive Order 13158, issued on May 26, 2000, directs federal agencies to safeguard existing Marine Protected Areas, or “MPAs,” in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate levels of protection for the marine environment. This order has the potential to adversely affect our operations by restricting areas in which we may carry out future exploration and development 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 Community Right-to-Know Act, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands and other protected areas and impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities.

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

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

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

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, 2007, we had 21 employees and utilized contract employees for certain of our field operations. We consider our employee relations to be satisfactory.

Directors, Executive Officers and Other Management

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


Name	Position	Age

M. Jay Allison	Chairman of the Board of Directors		52
Gary W. Blackie	Chief Executive Officer, President and Director		59
Roland O. Burns	Senior Vice President, Chief Financial Officer, Secretary and Director		47
Greg T. Martin	Chief Operating Officer		46
John L. Duvieilh	Director		47
D. Michael Harris	Director		61
Wayne L. Laufer	Director		62
David K. Lockett	Director		53
Cecil E. Martin, Jr	Director		66
David W. Sledge	Director		51

Executive Officers

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

Jay 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 Directors of Tidewater Marine, Inc., the Board of Regents for Baylor University and on the Advisory Board of the Salvation Army in Dallas, Texas.

Gary Blackiehas been our President since our formation in 2004 and was additionally appointed Chief Executive Officer in December 2007. 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 and a M.S. degree in geology/geophysics from Ohio University in 1971 and 1973, respectively. Mr. Blackie is a member of the American Association of Petroleum Geologists.

Roland 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. From 1982 to 1989, he was employed by the public accounting firm, Arthur Andersen. During his tenure with Arthur Andersen, Mr. Burns worked primarily in the firm’s oil and gas audit practice. Mr. Burns received B.A. and M.A. degrees from the University of Mississippi in 1982 and is a Certified Public Accountant.

Greg Martinwas appointed Chief Operating Officer in January 2008 and previously was our Vice President of Operations since our formation in 2004. Greg joined the predecessor to our company in July 1998 as a petroleum engineer responsible for all engineering activities. He earned a B.S. in Petroleum and Natural Gas Engineering from Pennsylvania State University in 1984. Greg has worked for Amerada Hess and Newfield Exploration prior to coming to Bois d’Arc.

Outside Directors

John 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.

Michael 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.

Wayne Lauferhas been a director since our formation in 2004. Mr. Laufer was our Chief Executive Officer until his retirement in November 2007. 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 several oil 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.

David 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 16 years and has spent the past 26 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.

Cecil 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 on the boards of directors of Crosstex Energy, Inc. and Crosstex Energy, L.P. Mr. Martin holds a B.B.A. degree from Old Dominion University and is a Certified Public Accountant.

David Sledgehas been a director since May 2005. Mr. Sledge is currently a Vice President of Basic Energy Services, Inc. He was President and Chief Operating Officer of Sledge Drilling Company until it was acquired by Basic Energy Services in April 2007. He served as an area operations manager forPatterson-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 100 F Street N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC 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, 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.

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, 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 70%, 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. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. The analysis that we perform using data from other wells, more fully explored 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 impacted in 2005 by hurricane and tropical storm activity.

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, 41% 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.


	We plan to conduct exploration, development and production operations on the deep shelf and in the deepwater 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. 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 70%. Of the 27 deep shelf wells that we have drilled, 17 successfully found hydrocarbons at geologic and drilling depths below 15,000 feet, for a success rate of 55%. 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. Deepwater development costs can also be significantly higher than shelf development costs because deepwater drilling requires bigger installation equipment; sophisticated sea floor production handling equipment; expensive, state-of-the-art platformsand/or investment in infrastructure. Deep shelf development can also 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. Accordingly, we cannot assure you that our oil and natural gas exploration activities, in the deep shelf, the deepwater and elsewhere, will be commercially successful.

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 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.

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.

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.

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. 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, 2007, approximately 41% of our total proved reserves were developednon-producing and approximately 26% 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.

One of our field areas comprise approximately 46% of the PV 10 Value of our total proved reserves. If our reserve estimates in this area 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 66% of our total proved reserves in our largest field area is 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.

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

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

We depend on our key management personnel and the loss of this individual 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 Gary W. Blackie, our Chief Executive Officer and President. Mr. Blackie also leads and is a key member of our technical team. Loss of the services of this individual 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 due to 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.


	•	lease permit restrictions;
	•	drilling bonds and other financial responsibility requirements, such as plug and abandonment bonds;
	•	spacing of wells;
	•	unitization and pooling of properties;
	•	safety precautions;
	•	regulatory requirements; and
	•	taxation.

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


	•	personal injuries;
	•	property and natural resource damages;
	•	well reclamation costs; and
	•	governmental sanctions, such as fines and penalties.

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

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.

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.

As of December 31, 2007 Comstock directly owned 32,224,661 shares of our common stock, representing approximately 49% of our voting interests and members of Comstock’s board of directors collectively owned 1,014,050 shares or 2% of our voting interests. Therefore, Comstock has the ability to exert significant influence and control 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.

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 2007.

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”. 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

2006 —	First Quarter	$	19.94	$	13.75
	Second Quarter		18.89		13.78
	Third Quarter		17.13		14.41
	Fourth Quarter		16.76		14.10

2007 —	First Quarter	$	15.65	$	12.49
	Second Quarter		17.94		13.01
	Third Quarter		20.06		15.35
	Fourth Quarter		23.64		17.90

As of February 28, 2008, we had 66,441,003 shares of common stock outstanding, which were held by 38 holders of record and approximately 3,100 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 in excess of $5.0 million.

The following table provides information about our repurchases during the periods indicated of equity securities that are registered by us pursuant to Section 12 of the Exchange Act:

Approximate maximum

Total number of

dollar value of

shares purchased as

shares that may yet

part of publicly

be purchased under

Total number of

Average price paid

announced plans or

the plans or

Period

shares purchased

per share⁽¹⁾

programs

programs⁽²⁾

December 2007

100,000

19.42

100,000

98,058,000


(1)		This amount represents the weighted average price paid per share and includes a per share commission for all repurchases.
(2)		On November 13, 2007, we announced that our Board of Directors had authorized our repurchase of up to an aggregate of $100.0 million of our common stock from time to time on the open market (the “2007 Share Repurchase Program”). The timing and amount of any shares repurchased is determined by our management based on its evaluation of market conditions and other factors. The 2007 Share Repurchase Program does not have a fixed term, and may be suspended or discontinued by us at any time. The 2007 Share Repurchase Program may be funded using our working capital, as well as proceeds from any credit facilities and other borrowing arrangements which we currently have or may enter into in the future.

The following table summarizes certain information regarding our equity compensation plans as of December 31, 2007:

Number of securities

Weighted average

Number of securities

to be issued upon

exercise price of

authorized for future

exercise of

outstanding

issuance under equity

outstanding options

options

compensation plans

Equity compensation plans approved by stockholders

3,422,000

8.11

2,021,185

⁽¹⁾


(1)		Plus 11% of any additional issuances of common stock each year beginning on each subsequent January 1.

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


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, 2007. The selected historical combined financial data as of and for the year ended December 31, 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 years ended December 31, 2005, 2006 and 2007 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 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			2006			2007
	(In thousands except per share data)

Oil and gas sales	$	133,450		$	70,341		$	72,721		$	184,436		$	254,710		$	355,460
Operating expenses:
Oil and gas operating⁽¹⁾		22,290			15,233			16,602			37,089			53,400			58,841
Exploration		800			2,676			12,040			16,794			18,708			36,040
Depreciation, depletion and amortization		44,285			22,831			21,761			42,854			77,591			115,285
Impairment		500			—			—			590			1,632			344
General and administrative, net		3,481			1,450			2,641			9,331			11,374			14,869

Total operating expenses		71,356			42,190			53,044			106,658			162,705			225,379

Income from operations		62,094			28,151			19,677			77,778			92,005			130,081
Other income (expenses):
Interest income		154			75			74			222			330			512
Interest expense		(9,580	)		(4,453	)		(2,665	)		(3,775	)		(6,696	)		(9,033	)
Formation costs		—			—			(1,838	)		—			—			—
Loss on disposal of assets		—			—			—			(89	)		—			—
Other income		—			—			—			—			597			541

Income before income taxes		52,668			23,773			15,248			74,136			86,236			122,101
Provision for income taxes		—			—			—			(125,808	)⁽²⁾		(31,212	)		(43,431	)

Net income before cumulative effect of change in accounting principle		52,668			23,773			15,248			(51,672	)		55,024			78,670
Cumulative effect of change in accounting principle		(739	)		—			—			—			—			—

Net income	$	51,929		$	23,773		$	15,248		$	(51,672	)	$	55,024		$	78,670

Income (loss) per share (unit):
Basic							$	0.30		$	(0.89	)	$	0.87		$	1.20

Diluted							$	0.30		$	(0.89	)	$	0.84		$	1.17

Weighted average common and common stock equivalent shares (units) outstanding:
Basic								50,000			57,909			63,391			65,392

Diluted								50,485			57,909			65,278			67,224

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 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)		Includes a deferred tax charge of $108.2 million recognized upon our conversion to a taxable entity.

Balance Sheet Data:


	Combined
	Bois d’Arc
	Energy
	Predecessors
	As of		Bois d’Arc Energy
	December 31,		As of December 31,
	2003		2004		2005		2006		2007
	(In thousands)

Cash and cash equivalents	$	22,019	$	2,416	$	12,043	$	9,487	$	18,841
Property and equipment, net		413,412		511,477		661,931		827,795		887,270
Total assets		461,693		530,583		712,902		885,501		956,636
Bank debt		10,500		—		69,000		100,000		80,000
Payable to Comstock Resources⁽¹⁾		311,706		148,066		—		—		—
Stockholders’ equity		64,949		319,485		419,206		516,610		602,498


(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.

Comparability of Results

The combined financial statements included in this report 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 accompanying consolidated financial statements reflect the consolidated results of the Company, including its financial position as of December 31, 2006 and 2007 and its results of operations for the years ended December 31, 2005, 2006 and 2007.

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 in May 2005, our earnings are subject to federal, state and local taxes at a combined rate of approximately 36%.


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, 2007, we owned interests in 145 (108.3 net to us) producing oil and natural gas wells in the federal and state waters of the Gulf of Mexico and we operate 122 of our 145 producing wells. 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 and production. 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 78 identified exploration prospects in our inventory that are located on our leasehold acreage and supported by3-D seismic data. 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 18 of these prospects in 2008. 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.

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. 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 hurricane activity, we deferred production of approximately 4.3 Bcfe in 2005 and 3.6 Bcfe in 2006. We incurred approximately $4.9 million and $3.0 million in costs to repair damage to our facilities caused by the hurricane activity in 2005 and 2006, 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 $45.1 million as of December 31, 2007.

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. Bois d’Arc Resources was the predecessor to Bois d’Arc Resources, Ltd., an entity owned by Gary W. Blackie and Wayne L. Laufer, who presently are directors, significant stockholders, and, in the case of Mr. Blackie, our chief executive officer. 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.

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 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.

Results of Operations

Our operating data for the years ended December 31, 2005, 2006 and 2007 is summarized below:


	Year Ended December 31,
	2005		2006		2007
	(In thousands, except per unit amounts)

Revenues:
Oil and gas sales	$	184,436	$	254,710	$	355,460
Expenses:
Oil and gas operating⁽¹⁾	$	37,089	$	53,400	$	58,841
Exploration	$	16,794	$	18,708	$	36,040
Depreciation, depletion and amortization	$	42,854	$	77,591	$	115,285
Net Production Data:
Oil (MBbls)		1,155		1,383		1,671
Natural gas (MMcf)		14,896		23,183		32,186
Natural gas equivalent (MMcfe)		21,825		31,481		42,211
Average Sales Price:
Oil ($/Bbl)	$	52.88	$	64.66	$	74.15
Natural gas ($/Mcf)	$	8.28	$	7.13	$	7.19
Average equivalent price ($/Mcfe)	$	8.45	$	8.09	$	8.42
Expenses ($ per Mcfe):
Oil and gas operating⁽¹⁾	$	1.70	$	1.70	$	1.39
Depreciation, depletion and amortization⁽²⁾	$	1.95	$	2.45	$	2.72


(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, 2007 Compared to Year Ended December 31, 2006

Oil and gas sales. Our oil and gas sales increased $100.8 million, or 40%, in 2007 to $355.5 million from $254.7 million in 2006. The increase in sales resulted from a 34% increase in our production and higher oil and natural gas prices in 2007. Our natural gas production increased by 39% and our oil production increased by 21%. The production increases related primarily to new wells that we drilled and the return to service of certain platforms that were shut-in because of the 2005 hurricanes. Our average realized oil price increased 15% in 2007 to $74.15 per Bbl from $64.66 per Bbl in 2006 and our average realized gas price in 2007 of $7.19 per Mcf was slightly higher than our average realized gas price of $7.13 per Mcf in 2006.

Oil and gas operating expenses. Our oil and gas operating expenses, including production taxes, increased $5.4 million, or 10%, to $58.8 million in 2007 from $53.4 million in 2006. Our operating expenses per equivalent Mcf produced were $1.39 and $1.70 for 2007 and 2006. The increase in total operating expenses was primarily related to increased production and new wells put on production in 2007. The decrease in operating expenses per Mcfe is due to the $3.0 million for costs in 2006 to repair damage resulting from the 2005 hurricane activity.

Impairment. We recorded an impairment to our oil and gas properties of $0.3 million and $1.6 million in 2007 and 2006, respectively, on minor valued fields.

Exploration expense. In 2007, we incurred $36.0 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 2006, our exploration expense was $18.7 million, which related to three dry holes and the acquisition and reprocessing of3-D seismic data.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased $37.7 million, or 49%, to $115.3 million in 2007 from $77.6 million in 2006 due to the higher production in 2007 combined with an increase in our per unit amortization rates in 2007. Our depreciation, depletion and amortization expense per equivalent Mcf produced increased by $0.27, or 11%, to $2.72 for 2007 as compared to $2.45 for 2006. The increase in the amortization rate was attributable to higher capitalized costs associated with the wells we drilled in 2006 and 2007.

General and administrative expenses. Our general and administrative expenses, which are reported net of operating fees that we receive, of $14.9 million in 2007 were $3.5 million or 31% higher than our net general and administrative expenses of $11.4 million in 2006. These costs have increased primarily as a result of increased personnel costs including stock-based compensation. Included in our general and administrative costs are stock-based compensation expense of $8.4 million and $6.4 million in 2007 and 2006, respectively. Stock-based compensation in 2007 includes $1.7 million for the acceleration of vesting in connection with the retirement of our former chief executive officer in November 2007.

Interest expense. Our interest expense for 2007 of $9.0 million was $2.3 million or 35% higher than interest expense of $6.7 million in 2006. Interest expense increased in 2007 primarily due to higher borrowings outstanding under our bank credit facility and higher interest rates. Our average borrowings of $113.7 million during 2007 increased from the $89.6 million average borrowings we had outstanding in 2006. Our average interest rate under our bank credit facility increased from 6.6% in 2006 to 6.8% in 2007.

Income taxes. Income tax expense increased in 2007 to $43.4 million from $31.2 million in 2006 due to our higher income. Our effective tax rate decreased to 35.6% in 2007 from 36.2% in 2006 mainly due to the increase in our taxable income and the increased credit for domestic production activities in 2007 as compared to 2006.

Net income. We reported net income of $78.7 million ($1.17 per share) for the year ended December 31, 2007 as compared to a net income of $55.0 million ($0.84 per share) for the year ended December 31, 2006.

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Oil and gas sales. Our oil and gas sales increased $70.3 million, or 38%, in 2006 to $254.7 million from $184.4 million in 2005. The increase in sales resulted from a 44% increase in our production, which was partially offset by lower natural gas prices in 2006. Our average realized gas price decreased by 14% and our average realized oil price increased by 22% in 2006 as compared with the average prices we realized in 2005. On an equivalent unit basis, the average price received for our production in 2006 was $8.09 per Mcfe, which was 4% lower than our average price received in 2005 of $8.45 per Mcfe. Our natural gas production increased by 56% while our oil production increased by 20%. The oil and natural gas production increase was primarily related to new discoveries that we made and the restoration of production from certain of our platforms with pipelines and onshore facilities returning to service during 2006 after being shut-in due to the 2005 hurricanes. The 2005 hurricane activity caused us to defer production of approximately 4.3 and 3.6 Bcfe in 2005 and 2006, respectively.

Oil and gas operating expenses. Our oil and gas operating expenses, including production taxes, increased $16.3 million, or 44%, to $53.4 million in 2006 from $37.1 million in 2005. Our operating expenses per equivalent Mcf produced were unchanged at $1.70 for 2006 and 2005. The increase in total operating expenses was primarily related to increased production and higher lifting costs associated with the

increased costs of services and materials and higher insurance costs following the 2005 hurricane activity. In addition, our oil and gas operating expenses included $3.0 million and $4.9 million in 2006 and 2005, respectively, for costs to repair damage resulting from the hurricane activity.

Impairment. We recorded an impairment to our oil and gas properties of $0.6 million and $1.6 million in 2005 and 2006, respectively, on minor valued fields.

Exploration expense. In 2006, we incurred $18.7 million in exploration expense, which related to the cost of three unsuccessful exploratory wells drilled and the acquisition and reprocessing of3-D seismic data. In 2005, our exploration expense was $16.8 million, which related to one dry hole and the acquisition and reprocessing of3-D seismic data.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased $34.7 million, or 81%, to $77.6 million in 2006 from $42.9 million in 2005. Our depreciation, depletion and amortization expense per equivalent Mcf produced increased by $0.50, or 26%, to $2.45 for 2006 as compared to $1.95 for 2005. The increase in the amortization rate was attributable to higher capitalized costs associated with the wells we drilled in 2006.

General and administrative expenses. Our general and administrative expenses, which are reported net of operating fees that we receive of $11.4 million in 2006, were $2.1 million or 22% higher than our net general and administrative expenses of $9.3 million in 2005. 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.

Interest expense. Our interest expense for 2006 was $6.7 million and $3.8 million in 2005. Interest expense increased in 2006 primarily due to higher borrowings outstanding under our bank credit facility and higher interest rates. Our average borrowings of $89.6 million during 2006 increased from the $74.1 million average borrowings we had outstanding in 2005. Our average interest rate increased to 6.6% in 2006 from 4.8% in 2005.

Income taxes. Income tax expense decreased in 2006 to $31.2 million from $125.8 million in 2005. The 2005 tax provision included a $108.2 million provision related to our conversion to a corporation.

Net income. We reported net income of $55.0 million ($0.84 per share) in 2006 as compared to a net loss of $51.7 million ($0.89 per share) year ended December 31, 2005. The net loss in 2005 resulted from the $108.2 million provision for the deferred tax liability upon our conversion to a corporation. Excluding this one time provision and pro forma for income taxes, we would have reported net income of $47.2 million ($0.79 per share) in 2005.

Liquidity and Capital Resources

Funding for our activities has historically been provided by net cash flow from operating activities, borrowings under our bank credit facility and issuances of common stock. In 2007 our primary source of funds was net cash flow from operating activities of $244.7 million. In 2006 our primary sources of funds were net cash flow from operating activities of $178.4 million, $31.0 million borrowed under our bank credit facility and $35.9 million from the proceeds from a sale of our common stock to Comstock in a private transaction. In 2005 our primary sources of funds were $131.7 million in net cash flow from operating activities, $69.0 million borrowed under our bank credit facility, and $145.1 million from our initial public offering.

Our cash flow from operating activities in 2007 increased by $66.3 million to $244.7 million as compared to $178.4 million in 2006 primarily due to our higher revenues in 2007 which were attributable to the 34% increase in our production and higher crude oil and natural gas prices. Our cash flow from operating activities in 2006 increased by $46.7 million to $178.4 million as compared to $131.7 million in 2005 primarily due to our higher revenues in 2006 which increased due to the 44% increase in our production.

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. Our capital expenditure activity for the years ended December 31, 2005, 2006 and 2007 is summarized in the following table:


	2005		2006		2007
	(In thousands)

Acquisitions of proved oil and gas properties	$	—	$	18,148	$	—
Acquisitions of unproved oil and gas leasehold		4,968		2,979		8,913
Exploration drilling⁽¹⁾		63,018		128,983		89,232
Development drilling		77,601		23,360		46,480
Offshore facilities		22,000		50,764		26,266
Other development costs		19,975		20,376		35,972
Other		2,209		1,611		83

Total	$	189,771	$	246,221	$	206,946


(1)		Excludes geological and geophysical expenses which are not capitalized and capitalized costs of asset retirement obligations.

Our capital expenditures in 2007 decreased by $39.3 million compared to 2006 mostly due to a decrease in exploration drilling and lower spending on acquisitions partially offset by increased development activity. Capital expenditures in 2006 increased by $56.4 million over 2005 mostly due to an acquisition and higher drilling and construction costs in the Gulf of Mexico.

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 currently expect to spend approximately $250.0 million in 2008, which includes $82 million on development projects and $168 million for exploration activity. Our 2008 capital program will be funded by cash flows generated from our operating activities. However, our operating cash flow and therefore, our capital expenditures, are highly dependent on oil and natural gas prices.

Cash used for financing activities in 2007 of $21.5 million was mainly comprised of repayments of $20.0 million under our bank credit facility and repurchases of shares of our common stock of $1.9 million. Our cash flow from financing activities of $66.7 million in 2006 increased $2.9 million as compared to $63.8 million in 2005. Financing activities in 2006 which funded our acquisition, exploration and development activities included additional borrowings under our bank credit facility and proceeds from sale of shares of our common stock to Comstock. Cash flows from financing activities in 2005 of $63.8 million included the proceeds from our initial public offering, the repayment of our borrowings from Comstock and borrowings under our bank credit facility which were used to fund our exploration and development projects.

On May 11, 2005 we completed an initial public offering of 13,500,000 shares of common stock at $13.00 per share to the public. We sold 12,000,000 shares of common stock and received proceeds of $145.1 million and a selling stockholder sold 1,500,000 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.

On August 31, 2006, we completed the sale of 2,250,000 shares of common stock to Comstock in a private transaction for $35.9 million. The private offering was priced at $15.94 per share, the closing market price as of August 25, 2006. Proceeds from the sale were used to fund an acquisition of oil and gas properties and our drilling program.

In December 2007 our board of directors approved a common stock repurchase plan providing for repurchases of up to $100.0 million of our outstanding common stock. We acquired 100,000 shares at an average cost of $19.42 per share under this plan in 2007.

We have a $350.0 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 $350.0 million, $270.0 million of which was available as of December 31, 2007. 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. We plan to extend the maturity of this facility during 2008. 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 in excess of $5.0 million, 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 least one-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.

The following table summarizes our aggregate contractual liabilities and commitments as of December 31, 2007 by year of maturity:


	2008		2009		2010		2011		2012		Thereafter		Total
	(In thousands)

Bank credit facility	$	—	$	80,000	$	—	$	—	$	—	$	—	$	80,000
Interest on debt obligations		4,864		1,746		—		—		—		—		6,610
Operating leases		397		418		436		453		136		—		1,840
Contracted drilling services		10,664		—		—		—		—		—		10,664
Acquisition of seismic data		8,250		—		—		—		—		—		8,250

	$	24,175	$	82,164	$	436	$	453	$	136	$	—	$	107,364

Future interest expense on debt obligations is computed based upon the December 31, 2007 rate on our bank credit facility.

The table above does not include estimated future payments for dismantlement, abandonment and restoration costs of oil and gas properties. These payments are currently estimated to be incurred primarily

after 2012. We record a separate liability for the fair value of these asset retirement obligations which totaled $45.1 million as of December 31, 2007. See Note 1, Asset Retirement Obligation to our consolidated financial statements in thisForm 10-K for further discussion.

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.

We do not have any off-balance sheet arrangements.

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.

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.

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 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. We evaluate our properties for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Expected future cash flows are determined using estimated future prices based on market based forward prices applied to projected future production volumes. The projected production volumes are based on the property’s proved and risk adjusted probable oil and natural gas reserve estimates at the end of the period. The oil and natural gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of actual prices on the last day of the period.

Asset retirement obligations. The Company has significant obligations to remove tangible equipment and facilities and to restore the seafloor at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Federal Taxation. 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. 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. Provision for federal and state corporate income taxes have been only with respect to our operations subsequent to our conversion to May 10, 2005. 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.

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. The Company adopted SFAS 123R utilizing the modified prospective transition method and accordingly the financial results for periods prior to January 1, 2006 have not been adjusted. Prior to adopting SFAS 123R the Company followed the fair value based method prescribed in Statement of Financial Accounting Standards No. 123, “Accounting for Stock Based Compensation” for all periods beginning January 1, 2004. 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. Because the Company previously recorded stock-based compensation using the fair value method, adoption of SFAS 123R did not have a significant impact on the Company’s net income or earnings per share for the year ended December 31, 2006.

New accounting standards. In June 2006, the FASB issued FASB Interpretation 48, “Accounting for Uncertainty in Income Taxes,” an interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adopted FIN 48 at the beginning of fiscal 2007. The impact of adoption was immaterial.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). This statement establishes a framework for fair value measurements in the financial statements by providing a single definition of fair value, provides guidance on the methods used to estimate fair value and increases disclosures about estimates of fair value. SFAS 157 will be effective for financial assets and liabilities in financial statements issued for fiscal years beginning after November 15, 2007, and will be effective for non-financial assets and liabilities in financial statements issued for fiscal years beginning after November 15, 2008. We are currently evaluating the impact of the adoption of this statement on our consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” which requires measurements based on fair value as determined under the provisions of SFAS 157 and is effective for financial statements issued for fiscal years beginning after December 15, 2008. SFAS 141R establishes accounting and reporting standards for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. This statement also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statement to evaluate the nature and financial effects of the business combination. SFAS 141R will impact the accounting and disclosures for any business combinations we engage in after January 1, 2009. However, the nature and magnitude of the specific effects will depend upon the nature, terms and size of the acquisitions we consummate after that date.

Related Party Transactions

One of our directors, Mr. Duvieilh, provides legal services to us and we have received administrative support services pursuant to a management services agreement from a business owned by Mr. Laufer’s spouse. Concurrent with Mr. Laufer’s retirement as our chief executive officer in November 2007 we entered into a management consulting agreement with Mr. Laufer with a term of one year and a total contract value of $600,000. Other than these relationships, we have not entered into any material transactions with our officers or directors apart from the compensation they are provided for their services. We also have not entered into any material business transactions with our significant stockholders or any other related parties except for the sale of 2,250,000 shares of our common stock to Comstock for $35.9 million in August 2006.


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 2007, 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 $1.7 million and a $1.00 change in the price per Mcf of natural gas would have changed our cash flow by approximately $32.0 million.

Interest Rates

At December 31, 2007, we had $80.0 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, 2007, a 100 basis point change in interest rates would change our annual interest expense on our variable rate debt by approximately $0.8 million.


ITEM 8.	*FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA*

Our consolidated financial statements are included on pages F-1 to F-24 of this report.

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

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 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 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

The management of Bois d’Arc Energy, Inc. (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.

As of December 31, 2007, management assessed the effectiveness of the Company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control — Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2007, based on those criteria.

Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report onForm 10-K, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007 is included below.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Bois d’Arc Energy, Inc.

We have audited Bois d’Arc Energy, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Bois d’Arc Energy, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, Bois d’Arc Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Bois d’Arc Energy, Inc. and subsidiaries as of December 31, 2006 and 2007, and the related consolidated statements of operations, members’ and stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007 and our report dated February 28, 2008 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 28, 2008


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 “Business — Directors, Executive Officers and Other Management” in thisForm 10-K, and to our definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2007.

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. We intend to disclose any amendments or waivers to these codes that apply to our Chief Executive Officer and senior financial officers on our website in accordance with applicable SEC rules. Please see the definitive proxy statement for our 2007 annual meeting, which will be filed with the SEC within 120 days of December 31, 2007 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, 2007.


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


ITEM 13.	*CERTAIN RELATIONSHIPS, RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE*


ITEM 14.	*PRINCIPAL ACCOUNTANT FEES AND SERVICES*

PART IV


ITEM 15.	*EXHIBITS AND FINANCIAL STATEMENT SCHEDULES*

1. The following consolidated financial statements and notes of Bois d’Arc Energy, Inc. are included on Pages F-2 to F-24 of this report.


Report of Independent Registered Public Accounting Firm			F-2
Consolidated Balance Sheets as of December 31, 2006 and 2007			F-3
Consolidated Statements of Operations for the Years Ended December 31, 2005, 2006 and 2007			F-4
Consolidated Statements of Changes in Members’ and Stockholders’ Equity for the Years Ended December 31, 2005, 2006 and 2007			F-5
Consolidated Statements of Cash Flows Years Ended December 31, 2005, 2006 and 2007			F-6
Notes to 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 consolidated financial statements or the related notes.

3. 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)).


Exhibit No.		Description

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).
10.7		First Amendment to Credit Agreement dated as of May 8, 2006 among Bois d’Arc Energy, Inc., the Banks and other Financial Institutions party thereto (incorporated by reference to Exhibit 10.1 to our Quarterly Report onForm 10-Q for the quarter ended March 31, 2006).
10.8		Second Amendment to Credit Agreement dated as of October 31, 2006 among Bois d’Arc Energy, Inc., the Banks and other Financial Institutions party thereto (incorporated by reference to Exhibit 10.1 to our Quarterly Report onForm 10-Q for the quarter ended September 30, 2006).
10.9		Third Amendment to Credit Agreement dated as of May 7, 2007 among Bois d’Arc Energy, Inc., the Banks and other Financial Institutions party thereto (incorporated by reference to Exhibit 10.1 to our Quarterly Report onForm 10-Q for the quarter ended March 31, 2007).
10.10*		Fourth Amendment to Credit Agreement dated as of November 20, 2007 among Bois d’Arc Energy, Inc., the Banks and other Financial Institutions party thereto.
10.11		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 (FileNo. 0-16741)).
10.12		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)).
10.13		Stock Purchase Agreement dated August 25, 2006, between Bois d’Arc Energy, Inc. and Comstock Resources, Inc. (incorporated by reference to Exhibit 2.1 to ourForm 8-K dated August 25, 2006).
10.14#		Change of Control Agreement dated June 1, 2007 between Bois d’Arc Energy, Inc. and M. Jay Allison (incorporated by Reference to Exhibit 99.1 to ourForm 8-K dated June 4, 2007).
10.15#		Change of Control Agreement dated June 1, 2007 between Bois d’Arc Energy, Inc. and Roland O. Burns (incorporated by Reference to Exhibit 99.2 to ourForm 8-K dated June 4, 2007).
10.16*#		Consulting Agreement dated November 30, 2007 between Bois d’Arc Energy, Inc. and Wayne L. Laufer.
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.

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/ GARY W. BLACKIE

Gary W. Blackie

Chief Executive Officer

(Principal Executive Officer)

Date: February 28, 2008

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	February 28, 2008

/s/ GARY W. BLACKIE Gary W. Blackie	Chief Executive Officer, President and Director (Principal Executive Officer)	February 28, 2008

/s/ ROLAND O. BURNS Roland O. Burns	Senior Vice President, Chief Financial Officer, Secretary, Treasurer and Director (Principal Financial and Accounting Officer)	February 28, 2008

/s/ JOHN L. DUVIEILH John L. Duvieilh	Director	February 28, 2008

/s/ D. MICHAEL HARRIS D. Michael Harris	Director	February 28, 2008

/s/ WAYNE L. LAUFER Wayne L. Laufer	Director	February 28, 2008

/s/ DAVID K. LOCKETT David K. Lockett	Director	February 28, 2008

/s/ CECIL E. MARTIN, JR. Cecil E. Martin, JR.	Director	February 28, 2008

/s/ DAVID W. SLEDGE David W. Sledge	Director	February 28, 2008

BOIS d’ARC ENERGY, INC.

FINANCIAL STATEMENTS

INDEX



Report of Independent Registered Public Accounting Firm			F-2
Consolidated Balance Sheets as of December 31, 2006 and 2007			F-3
Consolidated Statements of Operations for the Years Ended December 31, 2005, 2006 and 2007			F-4
Consolidated Statements of Changes in Members’ and Stockholders’ Equity for the Years Ended December 31, 2005, 2006 and 2007			F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2006 and 2007			F-6
Notes to Consolidated Financial Statements			F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

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, 2006 and 2007, and the related consolidated statements of operations, members’ and stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Bois d’Arc Energy, Inc. and subsidiaries at December 31, 2006 and 2007, and the consolidated results of their operations and cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States.

As discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), “Share Based Payment,” in accounting for equity-based compensation.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Bois d’Arc Energy, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2008 expressed an unqualified opinion thereon.

ERNST & YOUNG LLP

Dallas, Texas

February 28, 2008

F-2

BOIS d’ARC ENERGY, INC

CONSOLIDATED BALANCE SHEETS

As of December 31, 2006 and 2007


	December 31,
	2006			2007
	(In thousands)

ASSETS
Cash and Cash Equivalents	$	9,487		$	18,841
Accounts Receivable:
Oil and gas sales		27,018			37,628
Joint interest operations		11,494			4,382
Prepaid Expenses		8,795			5,451

Total current assets		56,794			66,302
Oil and Gas Properties:
Unevaluated properties		9,511			13,076
Proved properties		331,019			328,270
Wells and related equipment and facilities		832,718			1,003,655
Accumulated depreciation, depletion and amortization		(348,643	)		(460,606	)

Net oil and gas properties		824,605			884,395
Other Property and Equipment, net of accumulated depreciation of $1,311 and $1,889 at December 31, 2006 and 2007, respectively		3,190			2,875
Other Assets		912			3,064

	$	885,501		$	956,636


LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term Debt	$	3,250		$	2,588
Accounts Payable		60,776			37,660
Income Taxes Payable		3,867			5,170
Accrued Expenses		975			1,959

Total current liabilities		68,868			47,377
Long-term Debt		100,000			80,000
Deferred Income Taxes Payable		151,959			181,667
Reserve for Future Abandonment Costs		48,064			45,094

Total liabilities		368,891			354,138
Commitments and Contingencies
Stockholders’ Equity:
Common stock — $0.01 par, 100,000,000 shares authorized, 66,443,000 and 66,389,500 shares issued and outstanding at December 31, 2006 and 2007, respectively		664			664
Additional paid-in capital		497,346			504,564
Retained earnings		18,600			97,270

Total stockholders’ equity		516,610			602,498

	$	885,501		$	956,636

The accompanying notes are an integral part of these statements.

F-3

BOIS d’ARC ENERGY, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

For the Years Ended December 31, 2005, 2006 and 2007


	2005			2006			2007
	(In thousands except per share amounts)

Oil and gas sales	$	184,436		$	254,710		$	355,460
Operating expenses:
Oil and gas operating		37,089			53,400			58,841
Exploration		16,794			18,708			36,040
Depreciation, depletion and amortization		42,854			77,591			115,285
Impairments		590			1,632			344
General and administrative, net		9,331			11,374			14,869

Total operating expenses		106,658			162,705			225,379

Income from operations		77,778			92,005			130,081
Other income (expenses):
Interest income		222			330			512
Other income		—			597			541
Interest expense		(3,775	)		(6,696	)		(9,033	)
Loss on sale of assets		(89	)		—			—

Total other income (expenses)		(3,642	)		(5,769	)		(7,980	)

Income before income taxes		74,136			86,236			122,101
Provision for income taxes		(125,808	)		(31,212	)		(43,431	)

Net income (loss)	$	(51,672	)	$	55,024		$	78,670

Income (loss) per share (unit):
Basic	$	(0.89	)	$	0.87		$	1.20

Diluted	$	(0.89	)	$	0.84		$	1.17

Weighted average common and common stock equivalent shares (units) outstanding:
Basic		57,909			63,391			65,392

Diluted		57,909			65,278			67,224

Pro forma computation related to conversion to a corporation for income tax purposes:
Income before income taxes	$	74,136
Pro forma provision for income taxes		(26,914	)

Pro forma net income	$	47,222

Pro forma earnings per share (unit):
Basic	$	0.82

Diluted	$	0.79

Weighted average common and common stock equivalent shares (units) outstanding:
Basic		57,909

Diluted		59,655

The accompanying notes are an integral part of these statements.

F-4

BOIS d’ARC ENERGY, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’

AND STOCKHOLDERS’ EQUITY

For the Years Ended December 31, 2005, 2006 and 2007


										Common			Additional			Retained
	Class A			Class B			Common			Stock			Paid-In			Earnings
	Units			Units			Shares			Par Value			Capital			(Deficit)			Total
										(In thousands)

Balance at December 31, 2004	$	10		$	304,227			—		$	—		$	—		$	15,248		$	319,485
Conversion from LLC to a corporation		(10	)		(304,227	)		50,000			500			303,727			—			(10	)
Public offering of common stock		—			—			12,000			120			144,960			—			145,080
Stock issuance costs		—			—						—			(1,818	)		—			(1,818	)
Stock-based compensation		—			—			2,155			22			8,119			—			8,141
Net income (loss)		—			—			—			—			—			(51,672	)		(51,672	)

Balance at December 31, 2005		—			—			64,155			642			454,988			(36,424	)		419,206
Issuance of common shares		—			—			2,250			22			35,843			—			35,865
Stock issuance costs		—			—			—			—			(16	)		—			(16	)
Exercise of stock options		—			—			20			—			125			—			125
Tax benefit of stock option exercises		—			—			—			—			29			—			29
Stock-based compensation		—			—			9			—			6,377			—			6,377
Net income		—			—			—			—			—			55,024			55,024

Balance at December 31, 2006		—			—			66,434			664			497,346			18,600			516,610
Exercise of stock options		—			—			80			1			692			—			693
Tax benefit of stock option exercises		—			—			—			—			94			—			94
Stock-based compensation		—			—			(24	)		—			8,373			—			8,373
Repurchase of common stock		—			—			(100	)		(1	)		(1,941	)		—			(1,942	)
Net income		—			—			—			—			—			78,670			78,670

Balance at December 31, 2007	$	—		$	—			66,390		$	664		$	504,564		$	97,270		$	602,498

The accompanying notes are an integral part of these statements.

F-5

BOIS d’ARC ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2005, 2006 and 2007


	2005			2006			2007
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(51,672	)	$	55,024		$	78,670
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes		123,256			26,257			29,714
Depreciation, depletion and amortization		42,854			77,591			115,285
Impairments		590			1,632			344
Dry hole costs and lease impairments		2,353			14,070			29,053
Stock based compensation		5,634			6,377			8,373
Excess tax benefit from stock based compensation		—			(29	)		(94	)
Amortization of loan costs		141			243			348
Loss on sale of assets		89			—			—
Decrease in accounts receivable		(19,186	)		(4,628	)		(3,498	)
Increase (decrease) in other current assets		(2,769	)		(1,300	)		2,682
Increase (decrease) in accounts payable and accrued expenses		30,360			3,172			(16,204	)

Net cash provided by operating activities		131,650			178,409			244,673

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures and acquisitions		(185,998	)		(247,705	)		(211,483	)
Deposits paid for offshore leases		—			—			(2,330	)
Proceeds from sale of assets		160			—			—

Net cash used for investing activities		(185,838	)		(247,705	)		(213,813	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from Comstock Resources		16,000			—			—
Repayments to Comstock Resources		(164,066	)		—			—
Borrowings under bank credit facility		126,000			71,000			32,000
Repayments under bank credit facility		(57,000	)		(40,000	)		(52,000	)
Redemption of Class A Units		(10	)		—			—
Repurchase of common stock		—			—			(1,942	)
Excess tax benefit from stock based compensation		—			29			94
Proceeds from issuance of common stock		145,080			35,990			693
Stock and debt issuance costs		(2,189	)		(279	)		(351	)

Net cash provided by (used for) financing activities		63,815			66,740			(21,506	)

Net increase (decrease) in cash and cash equivalents		9,627			(2,556	)		9,354
Cash and cash equivalents, beginning of year		2,416			12,043			9,487

Cash and cash equivalents, end of year	$	12,043		$	9,487		$	18,841

Cash paid for interest payments	$	3,270		$	6,627		$	8,501

Cash paid (refunded) for income taxes	$	1,600		$	(435	)	$	12,325

The accompanying notes are an integral part of these statements.

F-6

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)	Organization and Basis of Presentation

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. Bois d’Arc was a predecessor in interest to Bois d’Arc Resources, Ltd., an entity owned by 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.

On July 16, 2004, Comstock Resources, Inc. (“Comstock”), Bois d’Arc Resources, Ltd. and Messrs. Blackie and Laufer formed Bois d’Arc Energy, LLC (“Bois d’Arc” or the “Company”) to replace a 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 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 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.

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.

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 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

F-7

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

conversion to a corporation on May 10, 2005, 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 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. 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. On May 10, 2005 the Company was converted from a limited liability company to a corporation.

The accompanying consolidated financial statements reflect the consolidated results of the Company, including its financial position as of December 31, 2006 and 2007 and its results of operations and cash flows for the years ended December 31, 2005, 2006 and 2007.


(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.

Principles of Consolidation

The consolidated financial statements include the accounts of Bois d’Arc Energy and its wholly owned subsidiaries and a majority owned subsidiary which is controlled by Bois d’Arc Energy. 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

F-8

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

high credit quality financial institutions that management believes have high credit ratings. 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, accounts payable and accrued expenses approximate fair value due to the short maturity of these instruments. The fair value of our floating rate bank credit facility approximates its carrying value.

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 equivalent unit-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 capitalized when asset retirement obligations are incurred and amortized 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 equivalent unit-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. Exploratory drilling costs are evaluated within a one-year period after the completion of drilling.

The Company assesses the need for an impairment of the costs capitalized for its oil and gas properties costs on a property or cost center basis. If impairment is indicated based on undiscounted expected future cash flows attributable to the property, then a provision for impairment is recognized to the extent that net capitalized costs exceed discounted expected future cash flows. Expected future cash flows are determined using estimated future prices based on market based forward prices applied to projected future production volumes. The projected production volumes are based on the property’s proved and risk adjusted probable oil and natural gas reserve estimates at the end of the period. The oil and natural gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of actual prices on the last day of the period. In 2006 and 2007, Bois d’Arc Energy recognized impairments of $1.6 million and $0.3 million, respectively, 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.

F-9

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

Asset Retirement Obligations

The Company records 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, this liability is accreted up to the final retirement cost. Accretion of the discount is included as part of depreciation, depletion and amortization in the accompanying consolidated financial statements. 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:


	2005			2006			2007
	(In thousands)

Beginning asset retirement obligations	$	28,253		$	35,034		$	48,064
New wells placed on production and changes in estimates		5,276			12,493			(5,983	)
Acquisition liabilities assumed		—			3,315			—
Liabilities settled		(422	)		(5,111	)		(75	)
Accretion expense		1,927			2,333			3,088

Ending asset retirement obligations	$	35,034		$	48,064		$	45,094

Segment Reporting

Bois d’Arc Energy 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, 2007, the Company had one purchaser of its oil and natural gas production that individually accounted for 10% or more of total oil and gas sales. During 2007, this purchaser accounted for 89% of total oil and gas sales. For the year ended December 31, 2006, the Company had two purchasers who individually accounted for 68% and 26% of total oil and gas sales, respectively. For the year ended December 31, 2005 the Company had two purchasers who individually accounted for 49% and 33% of total oil and gas sales, respectively. The loss of any of the foregoing customers would not have a material adverse effect on the Company as there is an available market for its crude oil and natural gas production from other purchasers.

Revenue Recognition and Gas Balancing

Bois d’Arc Energy utilizes the sales method of accounting for natural gas revenues whereby revenues are recognized at the time of delivery based on the amount of gas sold to purchasers. The amount of gas sold may differ from the amount to 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, 2005, 2006 or 2007.

F-10

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

General and Administrative Expense

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


	2005			2006			2007
	(In thousands)

General and administrative expense	$	12,364		$	15,856		$	20,010
Operating fee income		(3,033	)		(4,482	)		(5,141	)

General and administrative expense, net	$	9,331		$	11,374		$	14,869

The operating fee income is a reimbursement of the Company’s general and administrative expense.

Stock-based Compensation

The Company follows the fair value based method prescribed in Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”) 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. Effective January 1, 2006, the Company adopted SFAS 123R utilizing the modified prospective transition method and accordingly the financial results for periods prior to January 1, 2006 have not been adjusted. Prior to adopting SFAS 123R the Company followed the fair value based method prescribed in Statement of Financial Accounting Standards No. 123, “Accounting for Stock Based Compensation” for all periods beginning January 1, 2004. Because the Company previously recorded stock-based compensation using the fair value method, adoption of SFAS 123R did not have a significant impact on the Company’s net income or earnings per share for the year ended December 31, 2006.

Prior to adopting SFAS 123R, the Company presented all tax benefits of the deductions that resulted from stock-based compensation as cash flows from operating activities. SFAS 123R requires that excess tax benefits on stock-based compensation be recognized as a part of cash flows from financing activities. The Company had no excess tax benefits from stock-based compensation for the year ended December 31, 2005 and had $29,000 and $94,000 in excess tax benefits from stock-based compensation for the years ended December 31, 2006 and 2007, respectively, which have been included in cash flows from financing activities.

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

F-11

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as 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 were no differences between comprehensive income and reported income in the periods presented.

Statements of Cash Flows

For the purpose of the 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. At December 31, 2006 and 2007 the Company’s cash investments consisted of overnight Eurodollar deposits with a bank.

Earnings per Share

Basic earnings per share is determined without the effect of any outstanding potentially dilutive stock options, restricted stock or other convertible securities and diluted earnings per share is determined with the effect of outstanding stock options, restricted stock 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 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. Basic and diluted earnings per share for 2005, 2006 and 2007 were determined as follows:


	2005
	Income			Shares			Per Share			2006						2007
	(Loss)			(Units)⁽¹⁾			(Units)⁽¹⁾			Income		Shares		Per Share		Income		Shares		Per Share
	(In thousands except per share data)

Basic Earnings Per Share:
Net Income	$	(51,672	)		57,909		$	(0.89	)	$	55,024		63,391	$	0.87	$	78,670		65,392	$	1.20

Diluted Earnings Per Share:
Net income	$	(51,672	)		57,909		$	(0.89	)	$	55,024		63,391	$	0.87	$	78,670		65,392	$	1.20
Effect of dilutive securities:
stock grants and stock options		—			—	⁽²⁾					—		1,887				—		1,832

Net income	$	(51,672	)		57,909		$	(0.89	)	$	55,024		65,278	$	0.84	$	78,670		67,224	$	1.17


(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, 1,746 equivalent shares relating to stock grants and options were anti-dilutive to the net loss and excluded from the computation.

F-12

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Stock options and warrants to purchase common stock at exercise prices in excess of the average actual stock price for the period that were anti-dilutive and that were excluded from the determination of diluted earnings per share are as follows:


	2005		2006		2007
	(In thousands
	except per share data)

Weighted average anti-dilutive stock options		27		124		495
Weighted average exercise price	$	15.55	$	16.50	$	16.19

New Accounting Standards

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements” (SFAS 157). This statement establishes a framework for fair value measurements in the financial statements by providing a single definition of fair value, provides guidance on the methods used to estimate fair value and increases disclosures about estimates of fair value. SFAS 157 will be effective for financial assets and liabilities in financial statements issued for fiscal years beginning after November 15, 2007, and will be effective for non-financial assets and liabilities in financial statements issued for fiscal years beginning after November 15, 2008. The Company is currently evaluating the impact of the adoption of this statement on its consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141R”) which requires measurements based on fair value as determined under the provisions of SFAS 157 and is effective for financial statements issued for fiscal years beginning after December 15, 2008. SFAS 141R establishes accounting and reporting standards for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. This statement also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statement to evaluate the nature and financial effects of the business combination. SFAS 141R will impact the accounting and disclosures for any business combinations the Company engages in after January 1, 2009. However, the nature and magnitude of the specific effects will depend upon the nature, terms and size of the acquisitions we consummate after that date.


(3)	Acquisitions

During 2006, the Company acquired interests in certain producing oil and gas properties for approximately $18.1 million in cash. Proved oil and reserves associated with these purchases were 6.7 Bcfe.


(4)	Bank Credit Facility

The Company has a $350.0 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 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. The borrowing base was $350.0 million as of December 31, 2007, of which $270.0 million was available. 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

F-13

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 in excess of $5.0 million, 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 (plus availability under the credit facility) to current liabilities of one-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, 2007.


(5)	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 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.

On August 31, 2006, the Company completed the sale of 2,250,000 shares of Common Stock to Comstock for $35.9 million. The private offering was priced at $15.94 per share, the closing market price as of August 25, 2006. Proceeds from the sale were used to fund an acquisition of oil and gas properties and the Company’s drilling program. Following completion of this sale, Comstock owned approximately 49.5% of the Company’s shares of Common Stock.

F-14

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In December 2007 the board of directors approved a repurchase plan providing for repurchases of up to $100.0 million of Common Stock. During 2007, the Company repurchased 100,000 shares of Common Stock in open market purchases at an average purchase price of $19.42 per share.


(6)	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 Company recognized $5.6 million, $6.4 million and $8.4 million for the years ended December 31, 2005, 2006 and 2007, respectively, in stock-based compensation expense within general and administrative expenses. Stock-based compensation in 2007 includes $1.7 million for the acceleration in vesting in connection with the retirement of the Company’s former chief executive officer in November, 2007.

Stock Options. The Company amortizes the fair value of stock options granted over the vesting period using the straight-line method. The fair value of each award is estimated as of the date of grant using the Black-Scholes options pricing model. Total compensation expense recognized for all outstanding stock options for the years ended December 31, 2005, 2006 and 2007 was $2.7 million, $3.4 million and $4.4 million, respectively.

The following table summarizes the valuation assumptions for stock options for the years ended December 31, 2005, 2006 and 2007:


	2005		2006		2007

Weighted average grant date fair value	$	7.63	$	9.63	$	6.17
Weighted average assumptions used:
Expected volatility		37.0%		39.5%		36.4%
Expected lives		8.5 yrs.		9.8 yrs.		4.5 yrs.
Risk-free interest rates		4.2%		5.5%		4.9%
Expected dividend yield		—		—		—

The expected volatility for grants after the Company’s initial public offering in 2005 is calculated using an analysis of historical volatility of the Company’s common stock. The risk-free interest rates are determined using the implied yield currently available for zero-coupon U.S. government issues with a remaining term equal to the expected life of the options.

F-15

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes information related to stock options outstanding at December 31, 2007:


	Weighted Average		Number of	Number of
Exercise	Remaining Life		Options	Options
Price	(in years)		Outstanding	Exercisable

$6.00		5.8	2,686,000		1,798,000
$12.00		7.4	10,500		1,500
$12.80		2.4	25,000		25,000
$12.88		9.2	30,000		—
$14.23		8.5	40,000		8,000
$15.55		7.6	182,500		8,500
$15.62		8.5	40,000		8,000
$16.47		7.8	172,500		27,000
$16.68		8.9	205,500		—
$16.75		8.6	30,000		6,000

$8.11		6.3	3,422,000		1,882,000

The following tables summarize information related to stock option activity under the Incentive Plan for the years ended December 31, 2005, 2006 and 2007:


	2005				2006					2007
			Weighted					Weighted					Weighted
	Number of		Average		Number of			Average		Number of			Average
	Options		Exercise Price		Options			Exercise Price		Options			Exercise Price

Outstanding at January 1		2,800,000		$6.00		3,105,000			$6.84		3,350,500			$7.70
Granted		305,000		$14.60		364,000			$16.02		258,500			$16.24
Exercised		—				(19,500	)		$6.46		(80,000	)		$8.66
Forfeited		—				(99,000	)		$11.65		(107,000	)		$14.51

Outstanding at December 31,		3,105,000		$6.84		3,350,500			$7.70		3,442,000			$8.11

Vested and Exercisable at December 31,		560,000		$6.00		1,139,000			$6.24		1,882,000			$6.40


	2005		2006		2007
	(In thousands)

Cash received for options exercised	$	—	$	125	$	693
Actual tax benefit realized	$	—	$	172	$	731

As of December 31, 2007, total unrecognized compensation cost related to unvested options of $7.0 million was expected to be recognized over a period of 4.9 years. Options granted in 2005, 2006 and 2007 were granted with exercise prices equal to the closing prices of the Company’s common stock on the respective dates of grant and, therefore, had no intrinsic value on such grant dates. The aggregate intrinsic value of options outstanding at December 31, 2007 was $40.2 million based on the closing price for the Company’s common stock on December 29, 2007. The aggregate intrinsic value of vested Bois d’Arc Energy options was $25.3 million on December 31, 2007. The total intrinsic value of options exercised for the year ended December 31, 2006 and 2007 were $0.2 million and $0.7 million, respectively. There were no options exercised prior to 2006.

F-16

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Restricted Stock Grants. The Company amortizes the grant date fair value of the restricted shares over the vesting period using the straight-line method. Total compensation cost recognized for restricted stock grants was $2.9 million, $3.0 million and $4.0 million for the years ended December 31, 2005, 2006 and 2007, respectively. A summary of restricted stock activity under the Incentive Plan for the years ended December 31, 2005, 2006 and 2007 is presented below:


	Number of			Weighted
	Restricted			Average Grant
	Shares (Units)			Price

Outstanding at January 1, 2005		2,145,000			$6.80
Granted		10,000			$12.00
Vested		(429,000	)		$6.80

Outstanding at December 31, 2005		1,726,000			$6.83
Granted		25,000			$15.48
Vested		(429,000	)		$6.80
Forfeited		(16,000	)		$10.05

Outstanding at December 31, 2006		1,306,000			$6.97
Vested		(632,000	)		$6.80
Forfeited		(24,000	)		$14.03

Outstanding at December 31, 2007		650,000			$6.80

Total unrecognized compensation cost related to unvested restricted stock of $4.4 million as of December 31, 2007, is expected to be recognized over a period of 1.5 years. The fair value of restricted stock which vested during 2005, 2006 and 2007 was $6.1 million, $6.8 million and $11.6 million, respectively.


(7)	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. Bois d’Arc Energy’s matching contributions to the plan were $32,000, $41,000 and $84,000 in 2005, 2006 and 2007, respectively.

F-17

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(8)	Commitments and Contingencies

Commitments

The Company rents office space under a noncancelable lease that expires on April 30, 2012. Rent expense for 2005, 2006 and 2007 was $286,000, $358,000 and $380,000, respectively. Minimum future payments under the lease are as follows:


	(In thousands)

2008	$	397
2009		418
2010		436
2011		453
2012		136
Thereafter		—

	$	1,840

Bois d’Arc Energy has commitments to acquire seismic data totaling $8.3 million through December 2008. As of December 31, 2007, the Company has commitments for contracted drilling rigs of $10.7 million through April 2008.

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.


(9)	Related Party Transactions

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 was charged by Comstock under the credit facility in 2005. Borrowings outstanding under this credit facility were repaid using proceeds from the Company’s initial public offering in 2005.

An entity owned by the spouse of the Company’s former chief executive officer provided accounting services to Bois d’Arc under a service agreement. 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 was payable in monthly installments over a two year period that commenced in October 2004 and ended in September 2006. Subsequent to the formation of Bois d’Arc Energy, this entity performed services for the Company under a new consulting agreement. The Company paid $173,000 and $28,000 for such services in 2005 and 2006, respectively.

F-18

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Bois d’Arc Energy has a service agreement with Comstock pursuant to which Comstock provides accounting services to the Company. The Company paid Comstock $150,000 in 2005 and $60,000 in each of 2006 and 2007 under this service agreement.

The Company entered into a consulting agreement with its former chief executive officer in connection with his retirement in November 2007. The agreement is for a one year term and the total amount to be paid under this contract is $600,000.


(10)	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,
	2006			2007
	(In thousands)

Proved properties	$	1,163,737		$	1,331,925
Unproved properties		9,511			13,076
Accumulated depreciation, deletion and amortization		(348,643	)		(460,606	)

	$	824,605		$	884,395

Costs Incurred


	2005		2006		2007
	(In thousands)

Property acquisitions:
Proved properties	$	—	$	20,091	$	—
Unproved properties		5,159		2,979		8,913
Development costs		124,139		103,254		102,661
Exploration costs		77,750		133,620		96,219

	$	207,048	$	259,944	$	207,793


(11)	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 liability companies that pass through their taxable income to their owners. Accordingly, the provision for federal and state corporate income taxes in 2005 has been made only for the operations of Bois d’Arc Energy 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 its conversion to a corporation on May 10, 2005, the Company established a $108.2 million provision for deferred income taxes.

F-19

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following is an analysis of the consolidated income tax expense:


	2005		2006		2007
	(In thousands)

Current	$	2,552	$	4,955	$	13,717
Deferred		123,256		26,257		29,714

	$	125,808	$	31,212	$	43,431

In 2005, 2006 and 2007, Bois d’Arc Energy’s effective tax rate was 169.7%, 36.2% and 35.6%, respectively. The reconciliation of the provision computed at the effective tax rate of 35% to the amount computed by applying the statutory rate to income before provision for income taxes is as follows:


	2005			2006		2007
	(In thousands)

Income tax provision at the federal statutory rate of 35%	$	25,948		$	30,183	$	42,735
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			1,019		1,385
Other		—			10		(689	)

	$	125,808		$	31,212	$	43,431

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:


	Year Ended
	December 31,
	2005
	(In thousands)

Income before income taxes	$	74,136
Effective pro forma income tax rate		36	%

Pro forma income tax expense	$	26,914

F-20

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


	2006			2007
	(In thousands)

Noncurrent deferred tax assets (liabilities):
Property and equipment	$	(154,763	)	$	(185,507	)
Stock based compensation		2,539			3,900
Other assets		265			—
Other liabilities		—			(60	)

Net noncurrent deferred tax liability	$	(151,959	)	$	(181,667	)

Effective January 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (FIN 48), which clarifies the accounting and disclosure for uncertainty in tax positions. The Company has analyzed its filing positions in all jurisdictions where it is required to file income tax returns for the open tax years in such jurisdictions. The Company has identified its federal income tax return and its state income tax returns in Texas, and Louisiana, where it operations, as “major” tax jurisdictions. The Company’s federal income tax returns for the years subsequent to December 31, 2004 remain subject to examination. The Company’s income tax returns in major state income tax jurisdictions remain subject to examination for periods subsequent to December 31, 2004. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon audit. Therefore, the Company has no significant reserves for uncertain tax positions and no adjustments to such reserves were required upon adoption of FIN 48. Interest and penalties resulting from audits by tax authorities have been immaterial and are included in the provision for income taxes in the consolidated statements of operations.


(12)	Supplementary Quarterly Financial Data (Unaudited)


	2006
	First		Second		Third		Fourth		Total
	(In thousands, except per share amounts)

Total oil and gas sales	$	61,833	$	59,607	$	66,996	$	66,274	$	254,710

Income from operations	$	27,228	$	24,086	$	20,041	$	20,650	$	92,005

Net income	$	16,781	$	14,783	$	11,584	$	11,876	$	55,024

Net income per share (unit):
Basic	$	0.27	$	0.24	$	0.18	$	0.18	$	0.87

Diluted	$	0.26	$	0.23	$	0.18	$	0.18	$	0.84

F-21

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	2007
	First		Second		Third		Fourth		Total
	(In thousands, except per share amounts)

Total oil and gas sales	$	76,182	$	91,046	$	87,987	$	100,245	$	355,460

Income from operations	$	20,452	$	29,149	$	35,041	$	45,439	$	130,081

Net income	$	11,873	$	17,431	$	21,229	$	28,137	$	78,670

Net income per share:
Basic	$	0.18	$	0.27	$	0.32	$	0.43	$	1.20

Diluted	$	0.18	$	0.26	$	0.32	$	0.42	$	1.17


(13)	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 the years ended December 31, 2005, 2006 and 2007:


	2005						2006						2007
	Oil			Gas			Oil			Gas			Oil			Gas
	(MBbls)			(MMcf)			(MBbls)			(MMcf)			(MBbls)			(MMcf)

Proved Reserves:
Beginning of year		18,732			192,935			19,530			205,986			20,425			221,463
Revisions of previous estimates		(969	)		(22,043	)		(221	)		1,875			(1,405	)		25,266
Extensions and discoveries		2,922			49,990			1,934			33,454			1,485			29,587
Purchases of minerals in place		—			—			565			3,331			—			—
Improved recovery		—			—			—			—			5,798			6,004
Production		(1,155	)		(14,896	)		(1,383	)		(23,183	)		(1,671	)		(32,186	)

End of year		19,530			205,986			20,425			221,463			24,632			250,134

Proved Developed Reserves:
Beginning of year		14,278			167,730			15,316			175,838			15,636			183,003

End of year		15,316			175,838			15,636			183,003			17,390			189,249

F-22

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table sets forth the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2005, 2006 and 2007:


	2005			2006			2007
	(In thousands)

Cash Flows Relating to Proved Reserves:
Future Cash Flows	$	3,234,675		$	2,506,965		$	4,146,589
Future Costs:
Production		(313,342	)		(439,122	)		(591,581	)
Development and Abandonment		(169,238	)		(236,995	)		(340,846	)
Future Income taxes		(920,987	)		(319,142	)		(596,511	)

Future Net Cash Flows		1,831,108			1,511,706			2,617,651
10% Discount Factor		(548,683	)		(430,695	)		(836,362	)

Standardized Measure of Discounted Future
Net Cash Flows	$	1,282,425		$	1,081,011		$	1,781,289

The following table sets forth the changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2005, 2006 and 2007:


	2005			2006			2007
	(In thousands)

Standardized Measure, Beginning of period	$	996,724		$	1,282,425		$	1,081,011
Net Change in Sales Price, Net of Production Costs		687,692			(750,583	)		563,281
Development Costs Incurred During the Period Which Were Previously Estimated		28,319			43,736			78,385
Revisions of Quantity Estimates		(162,481	)		2,304			102,373
Accretion of Discount		99,672			192,803			131,712
Changes in Future Development and Abandonment Costs		(22,674	)		(44,955	)		(91,296	)
Extensions, Discoveries and Improved Recovery		475,944			206,676			476,080
Purchases of Reserves in Place		—			16,527			—
Sales, Net of Production Costs		(147,347	)		(201,310	)		(296,619	)
Changes in Timing of Production		(27,815	)		(76,112	)		(84,488	)
Net Changes in Income Taxes		(645,609	)		409,500			(179,150	)

Standardized Measure, End of period	$	1,282,425		$	1,081,011		$	1,781,289

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.

F-23

BOIS d’ARC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


	2005		2006		2007

Crude Oil (Per Barrel)	$	57.92	$	59.29	$	94.64
Natural Gas (Per Mcf)	$	10.21	$	5.85	$	7.26

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-24

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Good

Bois D Arc Energy (BDE) Inactive 10-K2007 FY Annual report

Content analysis