Edgar Filing: CONTANGO OIL & GAS CO

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2008


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 001-16317

CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)


DELAWARE		95-4079863
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

3700 BUFFALO SPEEDWAY, SUITE 960
HOUSTON, TEXAS 77098
(Address of principal executive offices)

(713) 960-1901
(Registrant’s telephone number, including area code)

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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


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

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

The total number of shares of common stock, par value $0.04 per share, outstanding as of May 5, 2008 was 16,609,221.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
QUARTERLY REPORT ON FORM 10-Q
FOR THE NINE MONTHS ENDED MARCH 31, 2008

TABLE OF CONTENTS


	Page
PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements
Consolidated Balance Sheets as of March 31, 2008 and June 30, 2007		3
Consolidated Statements of Operations for the three and nine months ended March 31, 2008 and 2007		5
Consolidated Statements of Cash Flows for the nine months ended March 31, 2008 and 2007		6
Consolidated Statement of Shareholders’ Equity for the nine months ended March 31, 2008		7
Notes to the Consolidated Financial Statements		8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 3. Quantitative and Qualitative Disclosures about Market Risk		42
Item 4. Controls and Procedures		42

PART II – OTHER INFORMATION

Item 1A. Risk Factors		43
Item 6. Exhibits		43
Fourth Amendment to Term Loan Agreement
Consent of William M. Cobb & Associates, Inc.
Certification Pursuant to Rules 13a-14(a) and 15d-14(a)
Certification Pursuant to Section 906

All references in this Form 10-Q to the “Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas Company and its wholly-owned Subsidiaries. Unless otherwise noted, all information in this Form 10-Q relating to natural gas and oil reserves and the estimated future net cash flows attributable to those reserves are based on estimates prepared by independent engineers and are net to our interest.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS


	March 31,			June 30,
	2008			2007
	(Unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	25,418,330		$	6,177,618
Restricted cash		13,342,115			—
Short-term investments		—			2,200,576
Inventory tubulars		334,797			334,797
Accounts receivable:
Trade receivables		9,960,371			7,853,080
Advances to affiliates		4,846,312			5,259,191
Joint interest billings receivable		27,752,336			7,894,505
Other receivables		439,926			—
Prepaid capital costs		1,796,381			5,539,419
Income tax receivable		—			2,666,884
Investment in Freeport LNG Project		—			3,243,585
Other		770,928			255,788

Total current assets		84,661,496			41,425,443


PROPERTY AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties		310,242,820			82,655,848
Unproved properties		14,610,412			22,012,054
Furniture and equipment		300,866			235,512
Accumulated depreciation, depletion and amortization		(8,049,731	)		(3,584,618	)

Total property and equipment, net		317,104,367			101,318,796


OTHER ASSETS:
Restricted cash		100,000,000			—
Cash and other assets held by affiliates		3,582,623			1,195,074
Investment in Contango Venture Capital Corporation		389,313			5,864,558
Deferred income tax asset		—			3,377,016
Facility fees and other assets		380,422			754,622

Total other assets		104,352,358			11,191,270

TOTAL ASSETS	$	506,118,221		$	153,935,509

The accompanying notes are an integral part of these consolidated financial statements.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY


	March 31,			June 30,
	2008			2007
	(Unaudited)
CURRENT LIABILITIES:
Accounts payable	$	19,253,051		$	14,659,860
Joint interest advances		13,697,896			—
Accrued exploration and development		12,926,640			14,235,062
Advances from affiliates		4,047,896			3,417,103
Debt of affiliates		19,753,195			8,540,091
Income tax payable		22,139,613			—
Other accrued liabilities		2,025,371			1,417,279

Total current liabilities		93,843,662			42,269,395


LONG-TERM DEBT		—			20,000,000
DEFERRED TAX LIABILITY		94,893,058			—
ASSET RETIREMENT OBLIGATION		2,039,515			862,344

SHAREHOLDERS’ EQUITY:
Convertible preferred stock, 6%, Series E, $0.04 par value, 10,000 shares authorized, 3,600 shares issued and outstanding at March 31, 2008, liquidation preference of $18,000,000 at $5,000 per share; 6,000 shares issued and outstanding at June 30, 2007, liquidation preference of $30,000,000 at $5,000 per share		144			240
Common stock, $0.04 par value, 50,000,000 shares authorized, 18,931,064 shares issued and 16,346,064 outstanding at March 31, 2008, 18,539,807 shares issued and 15,964,807 outstanding at June 30, 2007		757,241			741,591
Additional paid-in capital		72,357,585			75,849,506
Accumulated other comprehensive income		—			715,659
Treasury stock at cost (2,585,000 shares at March 31, 2008; 2,575,000 shares at June 30, 2007)		(6,843,900	)		(6,180,000	)
Retained earnings		249,070,916			19,676,774

Total shareholders’ equity		315,341,986			90,803,770

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	506,118,221		$	153,935,509

The accompanying notes are an integral part of these consolidated financial statements.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended						Nine Months Ended
	March 31,						March 31,
	2008			2007			2008			2007
REVENUES:
Natural gas, oil and liquids sales	$	20,779,574		$	4,517,434		$	47,256,798		$	6,198,225

Total revenues		20,779,574			4,517,434			47,256,798			6,198,225


EXPENSES:
Operating expenses		1,482,578			110,129			3,159,695			297,184
Exploration expenses		4,261,686			253,741			5,171,795			1,141,803
Depreciation, depletion and amortization		4,077,017			771,064			6,002,997			1,012,854
Impairment of natural gas and oil properties		837,098			—			837,098			192,109
General and administrative expenses		2,209,844			2,371,076			5,307,486			4,900,017

Total expenses		12,868,223			3,506,010			20,479,071			7,543,967

NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE OTHER INCOME AND INCOME TAXES		7,911,351			1,011,424			26,777,727			(1,345,742	)

OTHER INCOME (EXPENSE):
Interest expense (net of interest capitalized)		(1,425,715	)		(739,510	)		(3,585,074	)		(1,297,415	)
Interest income		914,826			231,253			1,763,335			638,395
Gain (loss) on sale of assets and other		59,919,478			(677,580	)		62,034,996			(1,994,265	)


NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		67,319,940			(174,413	)		86,990,984			(3,999,027	)
Benefit (provision) for income taxes		(23,557,442	)		61,095			(30,431,664	)		1,313,431

NET INCOME (LOSS) FROM CONTINUING OPERATIONS		43,762,498			(113,318	)		56,559,320			(2,685,596	)

DISCONTINUED OPERATIONS (NOTE 12)
Discontinued operations, net of income taxes		68,981,433			292,030			174,079,822			291,591

NET INCOME (LOSS)		112,743,931			178,712			230,639,142			(2,394,005	)
Preferred stock dividends		345,000			22,222			1,245,000			314,722

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	112,398,931		$	156,490		$	229,394,142		$	(2,708,727	)


NET INCOME (LOSS) PER SHARE:
Basic
Continuing operations	$	2.69		$	(0.01	)	$	3.45		$	(0.20	)
Discontinued operations		4.28			0.02			10.85			0.02

Total	$	6.97		$	0.01		$	14.30		$	(0.18	)

Diluted
Continuing operations	$	2.56		$	(0.01	)	$	3.30		$	(0.20	)
Discontinued operations		4.03			0.02			10.15			0.02

Total	$	6.59		$	0.01		$	13.45		$	(0.18	)


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		16,122,707			15,759,324			16,045,785			15,262,085

Diluted		17,127,187			16,068,154			17,155,007			15,262,085

The accompanying notes are an integral part of these consolidated financial statements.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended
	March 31,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) from continuing operations	$	56,559,320		$	(2,685,596	)
Plus income from discontinued operations, net of income taxes		174,079,822			291,591

Net income (loss)		230,639,142			(2,394,005	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		8,788,796			1,554,583
Impairment of natural gas and oil properties		837,098			192,109
Exploration expenditures		4,543,776			665,783
Deferred income taxes		98,655,429			(1,766,174	)
Tax benefit from exercise/cancellation of stock options		(694,555	)		(157,760	)
Stock-based compensation		1,170,850			1,158,069
Loss (gain) on sale of assets and other		(322,798,205	)		2,009,165
Changes in operating assets and liabilities:
Increase in accounts receivable and other		(2,107,291	)		(4,565,186	)
Increase in notes receivable		(250,000	)		(783,824	)
Increase in prepaid insurance		(608,923	)		(290,275	)
Increase in interest receivable		(563,681	)		(114,282	)
Increase in inventory		—			(139,972	)
Increase (decrease) in accounts payable and advances from joint owners		20,830,169			(1,701,283	)
Increase in other accrued liabilities		2,426,436			344,088
Increase in income taxes payable		25,501,052			157,760
Other		—			(14,900	)

Net cash provided by (used in) operating activities		66,370,093			(5,846,104	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures		(98,146,425	)		(54,991,543	)
Increase in restricted cash		(113,342,115	)		—
Sale of short-term investments		2,200,576			18,472,327
Additions to furniture and equipment		(43,078	)		(23,025	)
Sale of assets		395,672,421			7,000,000
Sale/acquisition costs		(7,847,613	)		—
Purchase of assets		(209,000,000	)		—
Investment in Contango Venture Capital Corporation		(1,166,624	)		(600,000	)

Net cash used in investing activities		(31,672,858	)		(30,142,241	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		20,000,000			20,000,000
Repayments under credit facility		(40,000,000	)		—
Borrowings by affiliates		11,213,104			8,540,091
Preferred stock dividends		(1,245,000	)		(314,722	)
Repurchase/cancellation of stock options and warrants		(5,922,532	)		(202,521	)
Tax benefit from exercise/cancellation of stock options		694,555			157,760
Purchase of treasury shares		(663,900	)		—
Proceeds from exercised options, warrants and others		580,760			434,755
Debt issuane/preferred shares costs		(113,510	)		(336,509	)

Net cash provided by (used in) financing activities		(15,456,523	)		28,278,854
NET DECREASE IN CASH AND CASH EQUIVALENTS		19,240,712			(10,103,496	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		6,177,618			10,274,950

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	25,418,330		$	171,454


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for taxes	$	2,542,034		$	451,993

Cash paid for interest	$	4,120,259		$	1,657,488

The accompanying notes are an integral part of these consolidated financial statements.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(Unaudited)


	For the Nine Months Ended March 31, 2008
															Accumulated
															Other									Total
	Preferred Stock						Common Stock					Paid-in			Comprehensive			Treasury			Retained			Shareholders’			Comprehensive
	Shares			Amount			Shares			Amount		Capital			Income			Stock			Earnings			Equity			Income
Balance at June 30, 2007		6,000		$	240			15,964,807		$	741,591	$	75,849,506		$	715,659		$	(6,180,000	)	$	19,676,774		$	90,803,770
Exercise of stock options		—			—			56,000			2,240		391,410			—			—			—			393,650
Tax benefit of exercising stock options		—			—			—			—		60,848			—			—			—			60,848
Issuance of restricted common stock		—			—			331			13		90,357			—			—			—			90,370
Net income		—			—			—			—		—			—			—			6,171,470			6,171,470			6,171,470
Preferred stock dividends		—			—			—			—		—			—			—			(450,000	)		(450,000	)
Expense of stock options		—			—			—			—		306,138			—			—			—			306,138
Unrealized loss on available for sale securities, net of tax		—			—			—			—		—			(754,383	)		—			—			(754,383	)		(754,383	)

Comprehensive income		—			—			—			—		—			—			—			—			—		$	5,417,087

Balance at September 30, 2007		6,000		$	240			16,021,138		$	743,844	$	76,698,259		$	(38,724	)	$	(6,180,000	)	$	25,398,244		$	96,621,863

Exercise of stock options		—			—			15,000			600		186,510			—			—			—			187,110
Tax benefit of exercising stock options		—			—			—			—		164,871			—			—			—			164,871
Issuance of restricted common stock		—			—			4,140			166		161,900			—			—			—			162,066
Net income		—			—			—			—		—			—			—			111,723,741			111,723,741			111,723,741
Preferred stock dividends		—			—			—			—		—			—			—			(450,000	)		(450,000	)
Expense of stock options		—			—			—			—		306,138			—			—			—			306,138
Unrealized gain on available for sale securities, net of tax		—			—			—			—		—			762,810			—			—			762,810			762,810

Comprehensive income		—			—			—			—		—			—			—			—			—		$	117,903,638

Balance at December 31, 2007		6,000		$	240			16,040,278		$	744,610	$	77,517,678		$	724,086		$	(6,180,000	)	$	136,671,985		$	209,478,599

Treasury shares at cost		—			—			(10,000	)		—		—			—			(663,900	)		—			(663,900	)
Conversion of Series E		(2,400	)		(96	)		315,786			12,631		(12,535	)		—			—			—			—
Tax benefit of cancelled stock options		—			—			—			—		468,836			—			—			—			468,836
Cancellation of options and warrants		—			—			—			—		(5,922,532	)		—			—			—			(5,922,532	)
Net income		—			—			—			—		—			—			—			112,743,931			112,743,931			112,743,931
Preferred stock dividends		—			—			—			—		—			—			—			(345,000	)		(345,000	)
Expense of stock options		—			—			—			—		306,138			—			—			—			306,138
Realized loss on available for sale securities, net of tax		—			—			—			—		—			(724,086	)		—			—			(724,086	)		(724,086	)

Comprehensive income		—			—			—			—		—			—			—			—			—		$	229,923,483

Balance at March 31, 2008		3,600		$	144			16,346,064		$	757,241	$	72,357,585		$	—		$	(6,843,900	)	$	249,070,916		$	315,341,986

The accompanying notes are an integral part of these consolidated financial statements.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Unaudited)

1. Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America for interim financial information, pursuant to the rules and regulations of the Securities and Exchange Commission, including instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature. The financial statements should be read in conjunction with the audited financial statements and notes included in the Company’s Form 10-K for the fiscal year ended June 30, 2007. The results of operations for the three and nine months ended March 31, 2008 are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2008.

2. Summary of Significant Accounting Policies

The application of generally accepted accounting principles involves certain assumptions, judgments, choices and estimates that affect reported amounts of assets, liabilities, revenues and expenses. Thus, the application of these principles can result in varying results from company to company. Contango’s significant accounting policies are described below.

Successful Efforts Method of Accounting. The Company follows the successful efforts method of accounting for its natural gas and oil activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, and any such impairment is charged to expense in the period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred. The provision for depreciation, depletion and amortization is based on the capitalized costs as determined above. Depreciation, depletion and amortization is on a cost center by cost center basis using the unit of production method, with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves.

When circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future net cash flows on a cost center basis to the unamortized capitalized cost of the asset. If the future undiscounted net cash flows, based on the Company’s estimate of future natural gas and oil prices and operating costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair market value. For the three months ended March 31, 2008, the Company recorded an impairment charge of $837,098. Of this amount, $245,361 relates to the expiration of two lease blocks at our partially-owned subsidiary, Contango Offshore Exploration LLC; Vioska Knoll 167 and Vermillion 231, and $591,737 relates to the Company’s 4,000 net mineral acres in the West Texas Barnett Shale play in Jeff Davis and Reeves Counties, Texas.

In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company classified its two Arkansas Fayetteville shale sales as discontinued operations. An integral and on-going part of our business strategy is to sell our proved reserves from time to time in order to generate additional capital to reinvest in our onshore and offshore exploration programs. Thus, it is our intent to remain an independent natural gas and oil company engaged in the exploration, production, and acquisition of natural gas and oil.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

Cash Equivalents. Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of March 31, 2008, the Company had approximately $25.4 million in cash and cash equivalents, of which approximately $16.1 million was invested in highly liquid AAA-rated tax exempt money market funds.

Restricted Cash. The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of March 31, 2008, the Company had approximately $113.3 million classified as restricted cash, pertaining to funds deposited in escrow to use in a like-kind exchange under Section 1031 of the U.S. federal tax code. The Company intends to use $100.0 million of these funds to acquire noncurrent assets. Accordingly, the restricted cash to be used for this purpose is classified as long term on the balance sheet.

Principles of Consolidation. The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries and affiliates, after elimination of all intercompany balances and transactions. Wholly-owned subsidiaries are fully consolidated. Exploration and development subsidiaries not wholly owned, such as 44.92% owned Republic Exploration LLC (“REX”) and 76.0% owned Contango Offshore Exploration LLC (“COE”) are not controlled by the Company and are proportionately consolidated.

Upon the formation of REX, Contango was the only owner that contributed cash, and under the terms of the limited liability company agreement, was entitled to all of REX’s assets and liabilities until REX expended all of the Company’s initial cash contribution. The Company therefore consolidated 100% of REX’s net assets and results of operations. During the quarter ended December 31, 2002, REX completed exploration activities to fully expend the Company’s initial cash contribution, thereby enabling each owner to share in the net assets of REX based on their stated ownership percentages. Commencing with the quarter ended December 31, 2002, the Company began consolidating 33.3% of the net assets and results of operations of REX. The reduction of our ownership in the net assets of REX resulted in a non-cash exploration expense of approximately $4.2 million. The other owners of REX contributed seismic data and related geological and geophysical services in exchange for their ownership interest.

Upon the formation of COE, Contango was the only owner that contributed cash, but by agreement, the owners in COE immediately shared in the net assets of COE, including the Company’s initial cash contribution, based on their stated ownership percentages. The Company therefore consolidated 66.6% of the venture’s net assets and results of operations. The other owner of COE contributed geological and geophysical services in exchange for its ownership interest.

On September 2, 2005, the Company purchased an additional 9.4% ownership interest in each of REX and COE. Both interests were purchased from an existing owner, which prior to the sale, owned 33.3% of each of the two subsidiaries. As a result of these two purchases, the Company’s equity ownership interest in REX has increased from 33.3% to 42.7% and in COE from 66.6% to 76.0%. On September 2, 2005, an independent third party also purchased a 9.4% interest in each of REX and COE and the selling owner’s ownership interest thus decreased from 33.3% to 14.6% in each such entity.

On January 3, 2008, one of the members of REX exchanged its membership interest in REX for a direct working interest in the Company’s Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) discoveries. As a result of this distribution, all of the member’s ownership interests were adjusted, and the Company’s new membership interest in REX was adjusted to 44.92%. In connection with this distribution, the member that exchanged its ownership interest pre-paid approximately $2.0 million of debt which REX had outstanding under a demand promissory note with a private investment company.

Contango’s 33% ownership of Moblize Inc. (“Moblize”) is currently accounted for using the equity method. Under the equity method, only Contango’s investment in and amounts due to and from the equity investee were included in the consolidated balance sheet.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

Recent Accounting Pronouncements. In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141(R) (“SFAS 141(R)”), “Business Combinations” and SFAS No. 160 (“SFAS 160”), “Noncontrolling Interests in Consolidated Financial Statements”. These statements require most identifiable assets, liabilities and noncontrolling interests to be recorded at full fair value and require noncontrolling interests to be reported as a component of equity. Both statements are effective for periods beginning on or after December 15, 2008, and earlier adoption is prohibited. SFAS 141(R) will be applied to business combinations occurring after the effective date and SFAS 160 will be applied prospectively to all noncontrolling interests, including any that arose before the effective date. We are currently evaluating the provisions of SFAS 141(R) and SFAS 160 and assessing the impact, if any, they may have on our financial position and results of operations.

Effective July 1, 2009, the FASB issued SFAS No. 157-2 (“SFAS 157-2”), “Effective Date of FASB Statement No. 157”. This pronouncement defers the effective date of SFAS 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years, for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). An entity that has issued interim or annual financial statements reflecting the application of the measurement and disclosure provisions of SFAS 157 prior to February 12, 2008, must continue to apply all provisions of SFAS 157. We are currently evaluating the impact of our adoption of SFAS 157-2 on our consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159 (“SFAS 159”), “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115.” This pronouncement permits entities to use the fair value method to measure certain financial assets and liabilities by electing an irrevocable option to use the fair value method at specified election dates. After election of the option, subsequent changes in fair value would result in the recognition of unrealized gains or losses as period costs during the period the change occurred. SFAS 159 becomes effective as of the beginning of the first fiscal year that begins after November 15, 2007, with early adoption permitted. However, entities may not retroactively apply the provisions of SFAS 159 to fiscal years preceding the date of adoption. We are currently evaluating the impact that SFAS 159 may have on our financial position, results of operations and cash flows.

In September 2006, the FASB issued SFAS No. 157 (“SFAS 157”), “Fair Value Measurements.” SFAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and requires enhanced disclosures about fair value measurements. It does not require any new fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We are currently evaluating the impact that SFAS 157 may have on our financial position, results of operations and cash flows.

Stock-Based Compensation. Effective July 1, 2001, the Company adopted the fair value based method prescribed in SFAS No. 123, “Accounting for Stock 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 over the award vesting period. The fair value of each award is estimated as of the date of grant using the Black-Scholes option-pricing model. Effective July 1, 2005, the Company adopted SFAS No. 123 (revised 2004) (“SFAS 123(R)”), “Share-Based Payment”. Prior to the adoption of SFAS 123(R), the Company presented all benefits from the exercise of share-based compensation as operating cash flows in the statement of cash flows. SFAS 123(R) requires the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) to be classified as financing cash flows. The fair value of each option is estimated as of the date of grant using the Black-Scholes option-pricing model. No options were granted for the three months ended March 31, 2008. For the three months ended March 31, 2007, the following weighted-average assumptions were used: (i) risk-free interest rate of 5.0 percent; (ii) expected life of five years; (iii) expected volatility of 56.0 percent and (iv) expected dividend yield of zero percent.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

Under the Company’s 1999 Stock Incentive Plan, as amended (the “1999 Plan”), the Company’s Board of Directors may also grant restricted stock awards to officers or other employees of the Company. Restricted stock awards made under the 1999 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board. Restricted stock awards generally vest over a period of three years. Grants of service-based restricted stock awards are valued at our common stock price at the date of grant. The Company did not grant options or shares of restricted stock to any officer or director for the three months ended March 31, 2008. For the three months ended March 31, 2007, the Company granted 200,000 options to the Chairman and CEO at a fair value of $11.25 per option, to be expensed over the vesting period. During the nine months ended March 31, 2008 and 2007, the Company recorded stock-based compensation charges of approximately $1.2 million for each period, to general and administrative expense for restricted stock and option awards previously granted.

3. Natural Gas and Oil Exploration and Production Risk

The Company’s future financial condition and results of operations will depend upon prices received for its natural gas and oil production and the cost of finding, acquiring, developing and producing reserves. Substantially all of its production is sold under various terms and arrangements at prevailing market prices. Prices for natural gas and oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control.

Other factors that have a direct bearing on the Company’s financial condition are uncertainties inherent in estimating natural gas and oil reserves and future hydrocarbon production and cash flows, particularly with respect to wells that have not been fully tested and with wells having limited production histories; the timing and costs of our future drilling; development and abandonment activities; access to additional capital; changes in the price of natural gas and oil; availability and cost of services and equipment; and the presence of competitors with greater financial resources and capacity. The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations, the amount of reported assets, liabilities and contingencies, and proved natural gas and oil reserves. We use the successful efforts method of accounting for our natural gas and oil activities.

4. Customer Concentration Credit Risk

The majority of the Company’s revenues for the nine months ended March 31, 2008 resulted from natural gas and oil sales to a single customer, Cokinos Energy Corporation. The receivables associated with these revenues are secured with letters of credit. We believe the loss of this purchaser would not have a material effect on our financial position or results of operations since there are numerous potential purchasers of our production.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

5. Net Income (Loss) per Common Share

A reconciliation of the components of basic and diluted net income (loss) per share of common stock is presented in the tables below.


	Three Months Ended						Three Months Ended
	March 31, 2008						March 31, 2007
			Weighted							Weighted
			Average		Per					Average			Per
	Income		Shares		Share		Income/(Loss)			Shares			Share
Net income (loss) attributable to common stock	$	43,417,498		16,122,707	$	2.69	$	(135,540	)		15,759,324		$	(0.01	)
Discontinued operations, net of income taxes	$	68,981,433		16,122,707	$	4.28	$	292,030			15,759,324		$	0.02

Basic Earnings per Share:
Net income attributable to common stock	$	112,398,931		16,122,707	$	6.97	$	156,490			15,759,324		$	0.01

Effect of Potential Dilutive Securities:
Stock options		—		305,003		—		—			308,830			—
Series D preferred stock		—		—		—		(a	)		(a	)		—
Series E preferred stock	$	345,000		699,477	$	0.49		—			—			—


Net income (loss), from continuing operations,	$	43,762,498		17,127,187	$	2.56	$	(135,540	)		16,068,154		$	(0.01	)
Discontinued operations, net of income taxes	$	68,981,433		17,127,187	$	4.03	$	292,030			16,068,154		$	0.02

Diluted Earnings per Share:
Net income, attributable to common stock	$	112,743,931		17,127,187	$	6.59	$	156,490			16,068,154		$	0.01

Anti-dilutive Securities:
Series D preferred stock	$	—		—			$	22,222			140,740		$	0.16


(a)		Anti-dilutive.


	Nine Months Ended						Nine Months Ended
	March 31, 2008						March 31, 2007
			Weighted							Weighted
			Average		Per					Average			Per
	Income		Shares		Share		Loss			Shares			Share
Net income (loss) attributable to common stock	$	55,314,320		16,045,785	$	3.45	$	(3,000,318	)		15,262,085		$	(0.20	)
Discontinued operations, net of income taxes	$	174,079,822		16,045,785	$	10.85	$	291,591			15,262,085		$	0.02

Basic Earnings per Share:
Net income (loss) attributable to common stock	$	229,394,142		16,045,785	$	14.30	$	(2,708,727	)		15,262,085		$	(0.18	)

Effect of Potential Dilutive Securities:
Stock options		—		349,747		—		—			(a	)		—
Series D preferred stock		—		—		—		(a	)		(a	)		—
Series E preferred stock	$	1,245,000		759,475	$	1.64		—			—			—


Net income (loss), from continuing operations,	$	56,559,320		17,155,007	$	3.30	$	(3,000,318	)		15,262,085		$	(0.20	)
Discontinued operations, net of income taxes	$	174,079,822		17,155,007	$	10.15	$	291,591			15,262,085		$	0.02

Diluted Earnings per Share:
Net income (loss), attributable to common stock	$	230,639,142		17,155,007	$	13.45	$	(2,708,727	)		15,262,085		$	(0.18	)

Anti-dilutive Securities:
Series D preferred stock	$	—		—			$	314,722			833,330		$	0.38


(a)		Anti-dilutive.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

6. Adoption of FIN 48 and FSP FIN 48-1

We adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (“FIN 48”) as of July 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We also adopted FASB Staff Position No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48” (“FSP FIN 48-1”) as of July 1, 2007. FSP FIN 48-1 provides that a company’s tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future. The adoption of FIN 48 and FSP FIN 48-1 had no effect on our financial position or results of operations. The Company did not derecognize any tax benefits, nor recognize any interest expense or penalties on unrecognized tax benefits as of the date of adoption. The Company currently does not anticipate a significant increase in unrecognized tax benefits during the next 12 months.

The Company files income tax returns in the United States and various state jurisdictions. The Company’s tax returns for 2005, 2006 and 2007 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed.

7. Contango Venture Capital Corporation

In March 2008, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, sold its direct and indirect investments in Gridpoint, Inc., Trulite, Inc., Protonex Technology Corporation, Jadoo Power Systems, Contango Capital Partners Fund, L.P. and Contango Capital Partnership Management, LLC for $3.4 million, recognizing a loss of approximately $2.9 million for the three months ended March 31, 2008. CVCC’s only remaining alternative energy investment was Moblize, Inc. (“Moblize”), in which the Company had invested $1.2 million in exchange for 648,648 shares of Moblize convertible preferred stock, which represents an approximate 33% ownership interest.

During the quarter ended March 31, 2008, the Company attempted to sell its interest in Moblize but could not find a purchaser. In March 2008, the Company determined that Moblize was partially impaired, and wrote down the investment to $0.6 million, recognizing a loss of $0.6 million for the three months ended March 31, 2008.

8. Series E Perpetual Cumulative Convertible Preferred Stock

On May 17, 2007, we sold $30.0 million of our Series E preferred stock to a group of private investors. The Series E preferred stock is perpetual and cumulative, is senior to our common stock and is convertible at any time into shares of our common stock at a price of $38.00 per share. Each record holder of Series E preferred stock is entitled to one vote per share for each share of common stock into which each share of Series E preferred stock is convertible. The dividend on the Series E preferred stock can be paid quarterly in cash at a rate of 6.0% per annum or paid-in-kind at a rate of 7.5% per annum. Our registration statement filed with the Securities and Exchange Commission, covering the 789,468 shares of common stock issuable upon conversion of the Series E preferred stock was declared effective on September 12, 2007. Net proceeds associated with the private placement of the Series E preferred stock was approximately $28.8 million, net of stock issuance costs.

Holders of common stock and holders of Series E preferred stock vote as one class for the election of directors and most other matters. Upon any liquidation or dissolution of the Company, the holders of common stock are entitled to receive a pro rata share of all of the assets remaining available for distribution to shareholders after settlement of all liabilities and liquidating preferences of preferred stockholders.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

As of March 31, 2008, four Series E preferred stockholders had voluntarily elected to convert a total of 2,400 shares of Series E preferred stock to 315,786 shares of common stock, par value $0.04 per share. The converted shares of Series E preferred stock had a face value of $12.0 million.

9. Long-Term Debt

As of March 31, 2008, the Company had no debt outstanding. The Company prepaid the $20.0 million it had outstanding under a three-year $20.0 million secured term loan facility with The Royal Bank of Scotland plc (the “RBS Facility”) on February 5, 2008, and terminated the RBS Facility. The Company paid an additional $342,292 in accrued and unpaid interest and prepayment fees.

On February 6, 2008, the Company pre-paid the $20.0 million it had outstanding under its secured term loan agreement with a private investment firm (the “Term Loan Agreement”). The commitments to fund under the Term Loan Agreement were increased from $30.0 million to $60.0 million on January 17, 2008. The Term Loan Agreement is secured with substantially all the assets of the Company. Borrowings under the Term Loan Agreement bear interest at 30 day LIBOR plus 5.0%. Accrued interest is due monthly and the Term Loan Agreement matures on June 30, 2009, but we may prepay at any time with no prepayment penalty. We pay a non-use fee in the amount of 1.50% per annum multiplied by such non-funded amount.

The Term Loan Agreement requires a minimum level of working capital and contains certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell certain assets, and pay dividends. Failure to maintain required working capital or comply with certain covenants in the Term Loan Agreement could result in a default and funds not being available for borrowing. As of March 31, 2008, the Company was in compliance with its financial covenants, ratios and other provisions of the Term Loan Agreement.

10. Acquisitions

Dutch and Mary Rose

On January 3, 2008, the Company acquired additional working interests in the Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) discoveries in a like-kind exchange, using escrowed funds from the sale of its Western core Fayetteville Shale properties. The Company purchased an additional 8.33% working interest and 6.67% net revenue interest in Dutch and an additional average 9.11% working interest and 6.67% net revenue interest in Mary Rose from three different companies for $200 million. We allocated 60%, or $120.0 million, of the purchase price to Dutch, and the remaining 40%, or $80.0 million, to Mary Rose. Of these three companies, one of them was the managing member of REX, who exchanged an ownership interest in REX for a direct working interest in Dutch and Mary Rose. The Company purchased a 2.45% working interest in Dutch and a 2.68% working interest in Mary Rose from this company for approximately $58.9 million. The effective date of the transactions was January 1, 2008.

On February 8, 2008, the Company acquired a 0.3% overriding royalty interest in the Dutch and Mary Rose discoveries for $9.0 million in a like-kind exchange, using escrowed funds from the sale of its Eastern core Fayetteville Shale properties. We allocated 60%, or $5.4 million, of the purchase price to Dutch, and the remaining 40%, or $3.6 million, to Mary Rose.

Pro Forma Results

The unaudited pro forma results presented below for the nine months ended March 31, 2008 and 2007 have been prepared to give effect to our 2008 acquisitions on our results of operations under the purchase method of accounting as if they had been consummated on July 1, 2007 and July 1, 2006. The unaudited pro forma results do not purport to represent what our results of operations actually would have been if these acquisitions had in fact occurred on such date or to project our results of operations for any future date or period. The results of our 2008 acquisitions for the three months ended March 31, 2008 are reflected in our revenues, net income, and earnings per share in our presented Consolidated Statements of Operations. The results for the three months ended March 31, 2007 are not material.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)


	Nine Months Ended
	March 31,
	2008		2007
	(Unaudited)		(Unaudited)
Pro Forma:
Revenues	$	51,957,274	$	7,014,121
Net income (loss)	$	59,446,827	$	(2,176,935	)
Basic earnings per share	$	3.63	$	(0.16	)
Diluted earnings per share	$	3.47	$	(0.16	)

11. Related Party Transactions

As of March 31, 2008, REX was party to a Demand Promissory Note (the “REX Demand Note”) with a private investment firm which was non-recourse to Contango. Under the terms of the REX Demand Note, REX could borrow up to $50.0 million at a per annum rate of 11.5% for the first advance, and a per annum rate of LIBOR plus 6.0% for each additional advance. All advances were payable in full on the earlier of October 26, 2008 or upon demand. As of January 1, 2008, REX had borrowed $41.0 million under the REX Demand Note. On January 3, 2008, in connection with our acquisition of additional working interests in Dutch and Mary Rose, one of the members of REX repaid approximately $2.0 million of the $41.0 million of debt REX had outstanding under the REX Demand Note. On March 20, 2008, REX borrowed an additional $5.0 million under the REX Demand Note. The Company was not a party to or guarantor of the REX Demand Note, but as a result of our proportionate consolidation of REX, approximately $19.8 million is reflected as a current liability on our balance sheet as of March 31, 2008. The REX Demand Note was secured by substantially all the assets of REX. For the three months ended March 31, 2008, the Company’s proportionate share of such interest expense was approximately $0.5 million.

On February 13, 2008, the Company’s Board of Directors approved the purchase of an aggregate of 99,333 stock options from three officers of the Company and one member of its Board of Directors for approximately $5.9 million, in the aggregate. The Board also approved the purchase of 10,000 shares of common stock from one member of its Board of Directors for approximately $0.7 million. All purchases were completed during the three months ended March 31, 2008. The Company does not have a program to repurchase shares of our common stock.

12. Sale of Properties — Discontinued Operations

On December 21, 2007, the Company completed the sale of its Western core Arkansas Fayetteville Shale properties to Petrohawk Energy Corporation for $199.2 million. The sale was effective October 1, 2007. The Company sold approximately 14,200 acres with 6.4 million cubic feet per day of production, net to Contango, and recognized a gain of approximately $156.4 million for the nine months ended March 31, 2008 as a result of this sale. As of December 31, 2007, the Company continued to own approximately 11,200 acres in the Eastern core Arkansas Fayetteville Shale, net to Contango, which were not part of the sale transaction.

On January 30, 2008, the Company completed the sale of its Eastern core Arkansas Fayetteville Shale properties to XTO Energy, Inc. for approximately $128.0 million, with an effective date of December 1, 2007. The Eastern core Arkansas Fayetteville Shale properties had a net carrying amount of approximately $16.9 million as of December 31, 2007. The Company recognized a gain of approximately $106.4 million for the nine months ended March 31, 2008 as a result of this sale.

In accordance with SFAS 144, we classified these property sales as discontinued operations in our financial statements for all periods presented.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (continued)

The summarized financial results for discontinued operations for the periods ended March 31, 2008 and 2007 are as follows:

Operating Results:


	Three Months Ended						Nine Months Ended
	March 31,						March 31,
	2008			2007			2008			2007
Revenues		(255,486	)		898,586			8,641,857			1,260,508
Operating expenses		(12,143	)		(170,173	)		(968,903	)		(260,769	)
Depletion expenses		—			(279,136	)		(2,785,799	)		(541,729	)
Exploration expenses		—			—			47,280			(9,408	)
Gain on sale of discontinued operations		106,392,910			—			262,880,675			—

Gain before income taxes		106,125,281			449,277			267,815,110			448,602
Provision for income taxes		(37,143,848	)		(157,247	)		(93,735,288	)		(157,011	)

Gain from discontinued operations, net of income taxes	$	68,981,433		$	292,030		$	174,079,822		$	291,591

13. Freeport LNG Development, L.P.

On February 5, 2008, the Company sold its 10% limited partnership interest in Freeport LNG for $68.0 million to an affiliate of Osaka Gas Company Ltd. The Company recognized a gain on sale of approximately $63.4 million.

14. Subsequent Events

On April 1, 2008, REX borrowed an additional approximately $6.0 million under the REX Demand Note, bringing the total amount outstanding under the REX Demand Note to $50.0 million.

On April 3, 2008, the members of REX entered into an Amended and Restated Limited Liability Company Agreement (the “REX LLC Agreement”), effective as of April 1, 2008, to, among other things, distribute REX’s interest in Dutch and Mary Rose to the individual members of REX or their designees. In connection with this distribution, REX repaid in full all amounts owing by REX to a private investment firm under the REX Demand Note, and all security interests and other liens granted in favor of such private investment firm as security for the obligations under the REX Demand Note have been released and terminated. The Company’s portion of such repayment was approximately $22.5 million.

Effective April 1, 2008, in connection with the REX LLC Agreement, the Company sold a portion of its membership interest in REX to an existing owner for approximately $0.8 million. As a result of the sale, the Company’s equity ownership interest in REX has decreased to 32.3%, effective April 1, 2008.

On April 3, 2008, the Company acquired additional working interests in the Dutch and Mary Rose discoveries in a like-kind exchange, using escrowed funds from the sale of its Eastern core Fayetteville Shale properties. The Company purchased an additional 4.17% working interest and 3.33% net revenue interest in Dutch and an additional average 4.56% working interest and 3.33% net revenue interest in Mary Rose from two different companies for $100 million. The estimated proved reserves purchased were 21 billion cubic feet equivalent. The effective date of the transaction is January 1, 2008.

On April 24, 2008, one of our Series E preferred stockholders voluntarily elected to convert a total of 2,000 shares of Series E preferred stock to 263,157 shares of common stock.

Available Information

General information about us can be found on our Website at www.contango.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our Website as soon as reasonably practicable after we file or furnish them to the Securities and Exchange Commission.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the financial statements and the accompanying notes and other information included elsewhere in this Form 10-Q and in our Form 10-K for the fiscal year ended June 30, 2007, previously filed with the Securities and Exchange Commission.

Cautionary Statement about Forward-Looking Statements

Some of the statements made in this report may contain “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, as amended. The words and phrases “should be”, “will be”, “believe”, “expect”, “anticipate”, “estimate”, “forecast”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. These include such matters as:

	•		Our financial position

	•		Business strategy, including outsourcing

	•		Meeting our forecasts and budgets

	•		Anticipated capital expenditures

	•		Drilling of wells

	•		Natural gas and oil production and reserves

	•		Timing and amount of future discoveries (if any) and production of natural gas and oil

	•		Operating costs and other expenses

	•		Cash flow and anticipated liquidity

	•		Prospect development

	•		Property acquisitions and sales

	•		Investments in alternative energy

Although we believe the expectations reflected in such forward-looking statements are reasonable, we cannot assure you that such expectations will occur. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from actual future results expressed or implied by the forward-looking statements. These factors include among others:

	•		Low and/or declining prices for natural gas and oil

	•		Natural gas and oil price volatility

	•		Operational constraints, start-up delays and production shut-ins at both operated and non-operated production platforms, pipelines and gas processing facilities

	•		The risks associated with acting as the operator in drilling deep high pressure wells in the Gulf of Mexico

	•		The risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry holes, especially in prospects in which the Company has made a large capital commitment relative to the size of the Company’s capitalization structure

	•		The timing and successful drilling and completion of natural gas and oil wells

	•		Availability of capital and the ability to repay indebtedness when due

	•		Availability of rigs and other operating equipment

	•		Ability to raise capital to fund capital expenditures

	•		Timely and full receipt of sale proceeds from the sale of our production

	•		The ability to find, acquire, market, develop and produce new natural gas and oil properties

	•		Interest rate volatility

	•		Uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures

	•		Operating hazards attendant to the natural gas and oil business

	•		Downhole drilling and completion risks that are generally not recoverable from third parties or insurance

	•		Potential mechanical failure or under-performance of significant wells, production facilities, processing plants or pipeline mishaps

	•		Weather

	•		Availability and cost of material and equipment

	•		Delays in anticipated start-up dates

	•		Actions or inactions of third-party operators of our properties

	•		Actions or inactions of third-party operators of pipelines or processing facilities

	•		The ability to find and retain skilled personnel

	•		Strength and financial resources of competitors

	•		Federal and state regulatory developments and approvals

	•		Environmental risks

	•		Worldwide economic conditions

	•		The ability to construct and operate offshore infrastructure, including pipeline and production facilities

	•		Successful commercialization of alternative energy technologies

	•		Drilling and operating costs, production rates and ultimate reserve recoveries in our Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) acreage.

	•		The ability of our working interest partners to fund their working interest commitment in our Dutch and Mary Rose development.

You should not unduly rely on these forward-looking statements in this report, as they speak only as of the date of this report. Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events. See the information under the heading “Risk Factors” in this Form 10-Q for some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in forward-looking statements.

Overview

Contango is a Houston-based, independent natural gas and oil company. The Company’s core business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico. Contango Operators, Inc. (“COI”), our wholly-owned subsidiary, acts as operator on certain offshore prospects.

Our Strategy

Our exploration strategy is predicated upon two core beliefs: (1) that the only competitive advantage in the commodity-based natural gas and oil business is to be among the lowest cost producers and (2) that virtually all the exploration and production industry’s value creation occurs through the drilling of successful exploratory wells. As a result, our business strategy includes the following elements:

Funding exploration prospects generated by our alliance partner. We depend totally upon our alliance partner, Juneau Exploration, L.P. (“JEX”), for prospect generation expertise. JEX has experience and a successful track record in exploration.

Using our limited capital availability to increase our reward/risk potential on selective prospects. We have concentrated our risk investment capital in our offshore Gulf of Mexico prospects. Exploration prospects are inherently risky as they require large amounts of capital with no guarantee of success. COI drills and operates these

offshore prospects. Should we be successful in any of our offshore prospects, we will have the opportunity to spend significantly more capital to complete development and bring the discovery to producing status.

Operating in the Gulf of Mexico. COI was formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico. Assuming the role of an operator represents a significant increase in the risk profile of the Company since the Company has limited operating experience. While COI has historically drilled turnkey wells, adverse weather conditions as well as difficulties encountered while drilling our offshore wells could cause our contracts to come off turnkey and thus lead to significantly higher drilling costs.

Sale of proved properties. From time-to-time as part of our business strategy, we have sold and in the future expect to continue to sell some or a substantial portion of our proved reserves and assets to capture current value, using the sales proceeds to further our exploration activities. Since its inception, the Company has sold approximately $483 million worth of natural gas and oil properties and facilities, and views periodic reserve sales as an opportunity to capture value, reduce reserve and price risk, and as a source of funds for potentially higher rate of return natural gas and oil exploration opportunities.

On February 5, 2008, the Company sold its 10% limited partnership interest in Freeport LNG Development, L.P. (“Freeport LNG”), a limited partnership formed to develop, construct and operate a 1.75 billion cubic feet per day (“Bcf/d”) liquefied natural gas (“LNG”) receiving terminal in Freeport, Texas, for $68 million. This property was held by Contango Sundance, Inc. (“Sundance”), a wholly-owned subsidiary of the Company. The Company had invested approximately $3.2 million and recognized a gain on sale of approximately $63.4 million for the three months ended March 31, 2008.

As further discussed under “Onshore Exploration and Properties — Arkansas Fayetteville Shale” below, the Company sold its Arkansas Fayetteville Shale properties for approximately $327.2 million within the past six months. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” we classified these property sales as discontinued operations for all periods presented.

Controlling general and administrative and geological and geophysical costs. Our goal is to be among the most efficient in the industry in revenue and profit per employee and among the lowest in general and administrative costs. With respect to our onshore prospects, we plan to continue outsourcing our geological, geophysical, and reservoir engineering and land functions, and partnering with cost efficient operators. We have six employees.

Structuring transactions to share risk. Our alliance partner shares in the upfront costs and the risk of our exploration prospects.

Structuring incentives to drive behavior. We believe that equity ownership aligns the interests of our partners, employees, and stockholders. Our directors and executive officers beneficially own or have voting control over approximately 23% of our common stock.

Exploration Alliance with JEX

Alliance with JEX. JEX is a private company formed for the purpose of assembling domestic natural gas and oil prospects. Under our agreement with JEX, JEX generates natural gas and oil prospects and evaluates exploration prospects generated by others. JEX focuses on the Gulf of Mexico, and generates offshore exploration prospects via our affiliated companies, REX and COE (see “Offshore Gulf of Mexico Exploration Joint Ventures” below).

Onshore Exploration and Properties

Arkansas Fayetteville Shale

On December 21, 2007, the Company completed the sale of its Western core Arkansas Fayetteville Shale properties to Petrohawk Energy Corporation for $199.2 million. The sale was effective October 1, 2007. The Company sold approximately 14,200 acres with 6.4 million cubic feet per day (“Mmcf/d”) of production, net to Contango. The Company recognized a gain of approximately $156.4 million for the nine months ended March 31, 2008 as a result of this sale.

On January 30, 2008, the Company completed the sale of its Eastern core Arkansas Fayetteville Shale properties to XTO Energy, Inc. for approximately $128.0 million. The sale was effective December 1, 2007. The Eastern core consisted of approximately 20,000 acres (11,200 acres net to Contango) and contained seven Alta-operated wells. Of these seven wells, two were producing 4.5 Mmcf/d as of December 31, 2007, or approximately 1.9 Mmcf/d net to Contango. The remaining five wells were either being drilled or were expected to be drilled over the next several months.

In addition, the Eastern core contained 62 wells in which the Company had been integrated by a third party independent oil and gas exploration company (the “Integrated Wells”). Of these 62 Integrated Wells, 34 were producing. The 8/8ths production rate for 30 of these 34 producing Integrated Wells was 20.4 Mmcf/d as of December 31, 2007 (approximately 1.1 Mmcf/d, net to Contango). Production data for the remaining four producing Integrated Wells was not available. The remaining 28 Integrated Wells were either being drilled or were expected to be drilled over the next several months. The Company recognized a gain of approximately $106.4 million for the nine months ended March 31, 2008 as a result of this sale.

Texas and Louisiana

The Company currently has an interest in two on-shore wells. The Alta-Ellis #1 is currently producing at a rate of 1.8 million cubic feet equivalent per day (“Mmcfe/d”) in Texas, and the Temple Inland #1 is currently producing at a rate of approximately 0.9 Mmcfe/d in Louisiana.

Offshore Gulf of Mexico Exploration Joint Ventures

Contango directly and through affiliated companies conducts exploration activities in the Gulf of Mexico. As of May 5, 2008, Contango and its affiliates have interests in 69 offshore leases. See “Offshore Properties” below for additional information on our offshore properties.

Republic Exploration LLC. Effective April 1, 2008, the Company sold a portion of its ownership interest in REX to an existing owner for approximately $0.8 million. As a result of the sale, the Company’s equity ownership interest in REX has decreased to 32.3%, effective April 1, 2008.

On March 19, 2008, REX was the apparent high bidder on one lease block at the Central Gulf of Mexico Lease Sale #206. REX bid $310,999 on Eugene Island 56. An apparent high bid (“AHB”) gives the bidding party priority in award of offered tracks, notwithstanding the fact that the Minerals Management Service (“MMS”) may reject all bids for a given tract. The MMS review process can take up to 90 days on some bids. Upon completion of that process, final results for all AHB’s will be known.

On March 12, 2008, the Company announced that its wildcat exploration well at High Island A198, a REX prospect, was determined to be a dry hole, at a cost of approximately $4.0 million. The well has been plugged and abandoned.

On March 7, 2008, REX elected to convert its 3.67% overriding royalty interest to an undivided 25% working interest in West Delta 36. REX also has a 20% net revenue interest in this well.

On January 1, 2008, REX was awarded High Island 263 for $1.75 million and High Island A38 for $1.1 million. REX had previously bid for these leases at the Western Gulf of Mexico Lease Sale No. 204 in August 2007. On December 1, 2007, REX was awarded Eugene Island 11, as part of Central Gulf of Mexico Lease Sale No. 205.

Contango Offshore Exploration LLC. Grand Isle 72 (“Liberty”), a COE prospect, began producing in March 2007 and as of May 5, 2008 was producing at an 8/8ths rate of approximately 0.4 Mmcfe/d. As of March 31, 2008, COE had invested approximately $5.5 million (approximately $4.2 million net to Contango) to drill and complete Grand Isle 72, including pipeline and production facility costs.

The MMS has implemented a rule on royalty relief for shallow water, deep shelf natural gas production from certain Gulf of Mexico leases. “Deep shelf gas” refers to natural gas produced from depths greater than 15,000 feet in waters of 200 meters or less. Royalty relief is available on the first 15 billion cubic feet (“Bcf”) of natural gas production if produced from an interval between 15,000 to less than 18,000 feet. Royalty relief is available on the first 25 Bcf of natural gas production if produced from an interval between 18,000 to less than 20,000 feet. Royalty relief is available on the first 35 Bcf of natural gas production if produced from well depths at or greater than 20,000 feet. This royalty relief is expected to have a positive impact on the economics of deep gas wells drilled on the shelf of the Gulf of Mexico.

Non-Operated Offshore Wells. The Company, through its partially-owned REX and COE subsidiaries, has net revenue interests in three producing offshore blocks: Ship Shoal 358, West Delta 36 and Eugene Island 113-B. The Company depends on third-party operators for the operation and maintenance of these production platforms. As of May 5, 2008, Ship Shoal 358, in which the Company has a 5.8% net revenue interest, was producing at an 8/8ths rate of approximately 3.8 Mmcfe/d. West Delta 36, in which the Company has a 6.46% net revenue interest, was producing at an 8/8ths rate of approximately 10.9 Mmcfe/d, and Eugene Island 113-B, in which the Company has a 1.1% net revenue interest, was producing at an 8/8ths rate of approximately 1.7 Mmcfe/d.

Contango Resources Company

Contango Resources Company (“CRC”), a wholly-owned subsidiary of the Company, was formed for the purpose of holding the direct working interest in Dutch and Mary Rose that was distributed by REX on April 3, 2008. REX distributed a 20.80% working interest in Dutch and a 23.82% working interest in Mary Rose to CRC. The Company’s remaining interest in Dutch and Mary Rose is held by COI. The Company plans to transfer all of COI’s interest in Dutch and Mary Rose to CRC, and qualify CRC as the operator of Dutch and Mary Rose.

The Company’s Board of Directors has authorized its financial advisor, Merrill Lynch & Co., to obtain proposals for the purchase of the Company’s Dutch and Mary Rose discoveries in the Gulf of Mexico. Any possible sale or restructuring is subject to mutually acceptable terms and conditions, mutually satisfactory documentation, the consent and approval of third parties and governmental authorities, the approval of the Contango Board of Directors and, if necessary, Contango shareholders. If Contango obtains an acceptable proposal to acquire its Dutch and Mary Rose discoveries, the disposition would likely be structured through the sale of Contango by its shareholders, with the potential purchaser acquiring the stock of Contango Oil & Gas Company and CRC.

The Company’s remaining assets would be simultaneously spun-off to our shareholders through our current subsidiary, Contango Energy Company. This structure would allow Contango shareholders to maintain an interest in any future exploration efforts at our other Gulf of Mexico leases.

Contango Operators, Inc.

COI is a wholly-owned subsidiary of Contango formed for the purpose of drilling exploration and development wells in the Gulf of Mexico. As part of our strategy, COI operates and acquires significant working interests in offshore exploration and development opportunities in the Gulf of Mexico, usually under a farm-out

agreement with either REX or COE. COI expects to take working interests in these prospects under the same arms-length terms offered to industry third party participants. COI also operates and acquires significant working interests in offshore exploration and development opportunities under farm-in agreements with third parties.

Current Activities. On April 29, 2008, the Company announced a successful development well at its Mary Rose #2 location in Louisiana state waters and announced that production had begun on its Mary Rose #1 and Mary Rose #3 wells. The Mary Rose #1 and #3 wells flow into the Company’s recently completed production platform at Eugene Island 11, and through its associated pipeline into the ANR Pipeline Company facilities at Eugene Island 63. The platform and pipeline have been designed with a capacity of 300 Mmcf/d and 6,000 barrels of oil per day (“Bbls/d”) and will process and transport anticipated production from four to six wells. As of May 5, 2008, Mary Rose #1 and Mary Rose #3 were producing at a combined 8/8ths production rate of approximately 88.5 Mmcfe/d. (approximately 35.0 Mmcfe/d net to Contango). As of March 31, 2008, the Company had invested approximately $5.2 million to drill and complete Mary Rose #1 and $5.8 million to drill and complete Mary Rose #3. As of March 31, 2008, the Company had invested approximately $3.2 million to drill Mary Rose #2 and approximately $4.1 million to build the platform and pipeline.

The Company is currently completing its Mary Rose #2 development well. The Company’s net revenue interest in this well is approximately 38.67%. Additionally, the Company is currently drilling its Mary Rose #4 exploration well, in which we have a net revenue interest of approximately 25.5%. Upon completion of Mary Rose #2 and if successful at Mary Rose #4, both wells will flow into the Company’s platform at Eugene Island 11.

On April 3, 2008, COI acquired additional working interests in the Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) discoveries in a like-kind exchange, using escrowed funds from the sale of its Eastern core Fayetteville Shale properties. COI purchased an additional 4.17% working interest and 3.33% net revenue interest in Dutch and an additional average 4.56% working interest and 3.33% net revenue interest in Mary Rose from three different companies for $100 million. The estimated proved reserves purchased were 21 billion cubic feet equivalent (“Bcfe”). The effective date of the transaction is January 1, 2008. On February 8, 2008, COI purchased an additional 0.3% overriding royalty interest in the Dutch and Mary Rose discoveries for $9.0 million in a like-kind exchange, using escrowed funds from the sale of its Eastern core Fayetteville Shale properties.

On January 3, 2008, COI purchased an additional 8.33% working interest and 6.67% net revenue interest in Dutch and an additional average 9.11% working interest and 6.67% net revenue interest in Mary Rose from three different companies for $200 million, in a like-kind exchange, using escrowed funds from the sale of its Western core Fayetteville Shale properties. The estimated proved reserves purchased were 29 Bcfe. The effective date of the transaction is January 1, 2008. As of May 5, 2008, the Company had a 47.05% working interest and 38.12% net revenue interest in Dutch, and an average 53.21% working interest and 39.00% net revenue interest in Mary Rose.

Effective February 1, 2008, the Company sold COI’s overriding royalty interest in Eugene Island 113-B, Ship Shoal 358 and Grand Isle 72 to JEX for $164,400.

Our three Dutch wells flow to a platform at Eugene Island 24, which is owned and operated by a third party. This platform recently underwent facility upgrades, at a cost of approximately $1.0 million, net to Contango, to permit us to increase the 8/8ths platform production capacity available to Contango and its partners for the three Dutch wells to 100 Mmcf/d and 2,000 Bbls/d. As of May 5, 2008, our three Dutch wells were flowing at a combined 8/8ths production rate of approximately 73.0 Mmcfe/d (approximately 27.8 Mmcfe/d net to Contango).

The Company’s independent third party engineer estimates the Dutch and Mary Rose discoveries to have total proved reserves of 635.2 Bcfe (231.7 Bcfe net to Contango).

Offshore Properties

Producing Properties. The following table sets forth the interests owned by Contango and related entities in the Gulf of Mexico which are producing natural gas or oil as of May 5, 2008:


Area/Block	WI			NRI			Status
Contango Operators, Inc.:
Eugene Island 10 #1		26.3	%		21.0	%	Producing
Eugene Island 10 #2		26.3	%		21.0	%	Producing
Eugene Island 10 #3		26.3	%		21.0	%	Producing
S-L 18640 #1		29.4	%		22.0	%	Producing
S-L 19266 #2		29.4	%		21.1	%	Producing

Contango Resources Company:
Eugene Island 10 #1		20.8	%		16.6	%	Producing
Eugene Island 10 #2		20.8	%		16.6	%	Producing
Eugene Island 10 #3		20.8	%		16.6	%	Producing
S-L 18640 #1		23.8	%		17.9	%	Producing
S-L 19266 #2		23.8	%		17.1	%	Producing

Contango Offshore Exploration LLC:
Ship Shoal 358, A-3 well		10.0	%		7.7	%	Producing
Grand Isle 72		50.0	%		40.0	%	Producing

Republic Exploration LLC:
Eugene Island 113B		0.0	%		3.3	%	Producing
West Delta 36		25.0	%		20.0	%	Producing

Farmed-Out Properties. The following table sets forth the working interests and net revenue interests owned by Contango and related entities in the Gulf of Mexico which have been farmed out as of May 5, 2008:


Area/Block	WI	NRI	Status
Republic Exploration LLC:
Vermilion 154	(1)	(1)	Drilling expected by summer 2008
Vermilion 73	(2)	(2)	Dry hole
South Marsh Island 247	(3)	(3)	Dry hole

Contango Offshore Exploration LLC:
East Breaks 369	—	—	Dry hole
East Breaks 370	(4)	(4)	No drilling date has been determined yet
Vermilion 154	(1)	(1)	Drilling expected by summer 2008


(1)		REX and COE will split a 25% back-in WI after payout.

(2)		Record title interest in lease has been assigned to a third party. REX is in negotiations to change terms to a 1.5% ORRI plus a 5% WI after payout.

(3)		Record title interest in lease has been assigned to a third party. REX has reserved a 5% of 8/8ths ORRI before payout.

(4)		Farmee has until September 1, 2008 to decide if East Breaks 370 will be drilled. COE will receive a 3.67% ORRI before project payout and a 6.67% ORRI after project payout.

Leases. The following table sets forth the working interests owned by Contango and related entities in the Gulf of Mexico as of May 5, 2008:


Area/Block	WI			Lease Date
Contango Operators, Inc.:
West Cameron 174		10.00	%	Jul-03
Grand Isle 63		25.00	%	May-04
Grand Isle 73		25.00	%	May-04
West Delta 43		35.00	%	May-04
S-L 18640 (LA)		29.39	%	Jul-05
S-L 18860 (LA)		29.39	%	Jan-06
Ship Shoal 14		37.50	%	May-06
Ship Shoal 25		37.50	%	May-06
South Marsh Island 57		37.50	%	May-06
South Marsh Island 59		37.50	%	May-06
South Marsh Island 75		37.50	%	May-06
South Marsh Island 282		37.50	%	May-06
Grand Isle 70		3.65	%	Jun-06
West Delta 77		25.00	%	Jun-06
Vermilion 194		37.50	%	Jul-06
Eugene Island 10		26.25	%	Nov-06
S-L 19261 (LA)		29.39	%	Feb-07
S-L 19266 (LA)		29.39	%	Feb-07
S-L 19396 (LA)		29.39	%	Jun-07
Eugene Island 11		29.39	%	Dec-07

Contango Resources Company.:
S-L 18640 (LA)		23.82	%	Jul-05
S-L 18860 (LA)		23.82	%	Jan-06
Eugene Island 10		20.80	%	Nov-06
S-L 19261 (LA)		23.82	%	Feb-07
S-L 19266 (LA)		23.82	%	Feb-07
S-L 19396 (LA)		23.82	%	Jun-07
Eugene Island 11		23.82	%	Dec-07

Republic Exploration LLC
West Cameron 174		90.00	%	Jul-03
High Island 113		100.00	%	Oct-03
South Timbalier 191		50.00	%	May-04
Vermilion 36		100.00	%	May-04
Vermilion 109		100.00	%	May-04
Vermilion 134		100.00	%	May-04
West Cameron 179		100.00	%	May-04
West Cameron 185		100.00	%	May-04
West Cameron 200		100.00	%	May-04
West Delta 18		100.00	%	May-04
West Delta 33		100.00	%	May-04
West Delta 34		100.00	%	May-04
West Delta 43		30.00	%	May-04
Ship Shoal 220		50.00	%	Jun-04
South Timbalier 240		50.00	%	Jun-04
West Cameron 133		100.00	%	Jun-04


Area/Block	WI			Lease Date
Republic Exploration LLC (cont’d)
West Cameron 80		100.00	%	Jun-04
West Cameron 167		100.00	%	Jun-04
Eugene Island 76		0.00	%	Jul-04
Vermilion 130		100.00	%	Jul-04
West Cameron 107		100.00	%	May-05
Eugene Island 168		50.00	%	Jun-05
High Island A243		75.00	%	Jan-06
South Marsh Island 57		50.00	%	May-06
South Marsh Island 59		50.00	%	May-06
South Marsh Island 75		50.00	%	May-06
South Marsh Island 282		50.00	%	May-06
Ship Shoal 14		50.00	%	May-06
Ship Shoal 25		50.00	%	May-06
West Delta 77		50.00	%	Jun-06
Vermilion 194		50.00	%	Jul-06
High Island A196		100.00	%	Nov-06
High Island A197		100.00	%	Nov-06
High Island A198		100.00	%	Nov-06
High Island 263		100.00	%	Jan-08
High Island A38		100.00	%	Jan-08

Contango Offshore Exploration LLC:
Ship Shoal 358, A-3 well		10.00	%	Jun-98
Viosca Knoll 161		50.00	%	Jul-03
Eugene Island 209		100.00	%	Jul-03
High Island A16		100.00	%	Dec-03
East Breaks 283		100.00	%	Dec-03
South Timbalier 191		50.00	%	May-04
Grand Isle 63		50.00	%	May-04
Grand Isle 72		50.00	%	May-04
Grand Isle 73		50.00	%	May-04
Ship Shoal 220		50.00	%	Jun-04
South Timbalier 240		50.00	%	Jun-04
Viosca Knoll 118		50.00	%	Jun-04
Viosca Knoll 475		100.00	%	May-05
Eugene Island 168		50.00	%	Jun-05
East Breaks 366		100.00	%	Nov-05
East Breaks 410		100.00	%	Nov-05
East Breaks 167		75.00	%	Dec-05
High Island A311		75.00	%	Dec-05
East Breaks 166		75.00	%	Jan-06
High Island A342		75.00	%	Jan-06
Ship Shoal 263		75.00	%	Jan-06
Viosca Knoll 383		100.00	%	Jan-06
Grand Isle 70		52.60	%	Jun-06
Viosca Knoll 119		50.00	%	Jun-06

Contango Venture Capital Corporation

In March 2008, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, sold its direct and indirect investments in Gridpoint, Inc., Trulite, Inc., Protonex Technology Corporation, Jadoo Power Systems, Contango Capital Partners Fund, L.P. and Contango Capital Partnership Management, LLC for $3.4 million, recognizing a loss of approximately $2.9 million for the three months ended March 31, 2008. CVCC’s only remaining alternative energy investment is Moblize, Inc. (“Moblize”), in which the Company has invested $1.2

million in exchange for 648,648 shares of Moblize convertible preferred stock, which represents an approximate 33% ownership interest.

Application of Critical Accounting Policies and Management’s Estimates

The discussion and analysis of the Company’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. The Company’s significant accounting policies are described in Note 1 to the consolidated financial statements included in this Quarterly Report on Form 10-Q. We have identified below the policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. The Company analyzes its estimates, including those related to its natural gas and oil reserve estimates, on a periodic basis and bases its estimates on historical experience, independent third party reservoir engineers and various other assumptions that management believes to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of the Company’s financial statements:

Successful Efforts Method of Accounting. Our application of the successful efforts method of accounting for our natural gas and oil business activities requires judgments as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties requires management’s judgment to estimate the fair value of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

Reserve Estimates. The Company’s estimates of natural gas and oil reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future natural gas and oil prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil attributable to any particular group of properties,

classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s natural gas and oil properties and/or the rate of depletion of such natural gas and oil properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material. Holding all other factors constant, a reduction in the Company’s proved reserve estimate at March 31, 2008 of 1% would not have a material effect on depreciation, depletion and amortization.

Impairment of Natural Gas and Oil Properties. The Company reviews its proved natural gas and oil properties for impairment on an annual basis or whenever events and circumstances indicate a potential decline in the recoverability of their carrying value. The Company compares expected undiscounted future net cash flows on a cost center basis to the unamortized capitalized cost of the asset. If the future undiscounted net cash flows, based on the Company’s estimate of future natural gas and oil prices and operating costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair market value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Given the complexities associated with natural gas and oil reserve estimates and the history of price volatility in the natural gas and oil markets, events may arise that will require the Company to record an impairment of its natural gas and oil properties and there can be no assurance that such impairments will not be required in the future nor that they will not be material.

Stock-Based Compensation. Effective July 1, 2006, we adopted SFAS No. 123 (revised 2004) (“SFAS 123(R)”), “Share-Based Payment” which requires companies to measure and recognize compensation expense for all stock-based payments at fair value. SFAS 123(R) requires that management make assumptions including stock price volatility and employee turnover that are utilized to measure compensation expense. The fair value of stock options granted is estimated at the date of grant using the Black-Scholes option-pricing model. This model requires the input of highly subjective assumptions, which are set forth in Note 1 to our consolidated financial statements.

MD&A Summary Data

The table below sets forth revenue, expense and production data for continuing operations for the three and nine months ended March 31, 2008 and 2007.


	Three Months Ended								Nine Months Ended
	March 31,								March 31,
	2008		2007			Change			2008		2007			Change
Revenues:				($000	)							($000	)
Natural gas, oil and NGL sales	$	20,780	$	4,517			360	%	$	47,257	$	6,198			662	%

Total revenues	$	20,780	$	4,517			360	%	$	47,257	$	6,198			662	%


Production:
Natural gas (million cubic feet)		1,555		499			212	%		4,651		687			577	%
Oil and condensate (thousand barrels)		38		12			217	%		95		17			459	%
Natural gas liquids (thousand gallons)		1,403		*			100	%		2,218		*			100	%

Total (million cubic feet equivalent)		1,983		571			247	%		5,538		789			602	%

Natural gas (million cubic feet per day)		17.1		5.5			208	%		16.9		2.5			575	%
Oil and condensate (thousand barrels per day)		0.4		0.1			213	%		0.3		0.1			457	%
Natural gas liquids (thousand gallons per day)		15.4		*			100	%		8.1		*			100	%

Total (million cubic feet equivalent per day)		21.7		6.1			256	%		19.9		3.1			542	%

Average Sales Price:
Natural gas (per thousand cubic feet)	$	7.35	$	7.75			-5	%	$	7.69	$	7.55			2	%
Oil and condensate (per barrel)	$	102.48	$	56.20			82	%	$	87.22	$	59.81			46	%
Natural gas liquids (per gallon)	$	1.56		*			100	%	$	1.45		*			100	%

Operating expenses	$	1,483	$	110			1248	%	$	3,160	$	297			964	%
Exploration expenses	$	4,262	$	254			1578	%	$	5,172	$	1,142			353	%
Depreciation, depletion and amortization	$	4,077	$	771			429	%	$	6,003	$	1,013			493	%
Impairment of natural gas and oil properties	$	837	$	—			100	%	$	837	$	192			336	%
General and administrative expenses	$	2,210	$	2,371			-7	%	$	5,307	$	4,900			8	%
Interest expense, net of interest capitalized	$	1,426	$	740			93	%	$	3,585	$	1,297			176	%
Interest income	$	915	$	231			296	%	$	1,763	$	638			176	%
Gain (loss) on sale of asset and other	$	59,919	$	(678	)		8938	%	$	62,035	$	(1,994	)		3211	%


*		Not meaningful

Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007

Natural Gas, Oil and Natural Gas Liquids (“NGL”) Sales. We reported revenues of approximately $20.8 million for the three months ended March 31, 2008, compared to revenues of approximately $4.5 million for the three months ended March 31, 2007. This increase is mainly attributable to increased production from our Dutch #2 discovery which began producing in July 2007 and our Dutch #3 discovery which began producing in November 2007, as well as a general increase in oil and condensate prices.

For the three months ended March 31, 2008, the price of natural gas was $7.35 per thousand cubic feet (“Mcf”) while the price for oil and condensate was $102.48 per barrel and the price for NGLs was $1.56 per gallon. For the three months ended March 31, 2007, the price of natural gas was $7.75 per Mcf while the price for oil and condensate was $56.20 per barrel. The Company did not have a material quantity of NGL sales for the three months ended March 31, 2007.

Natural Gas, Oil and NGL Production and Average Sales Prices. Our net natural gas production for the three months ended March 31, 2008 was approximately 17.1 Mmcf/d, up from approximately 7.1 Mmcf/d for the three months ended March 31, 2007. Net oil and condensate production for the comparable periods also increased from approximately 100 barrels per day to approximately 400 barrels per day. Our NGL production for the three months ended March 31, 2008 was approximately 15,400 gallons per day. This increase in natural gas, oil and NGL production is principally attributable to Dutch #2 which began producing in July 2007 and Dutch #3 which began producing in November 2007.

Operating Expenses. Lease operating expenses for the three months ended March 31, 2008 and the three months ended March 31, 2007 were $1.5 million and $0.1 million, respectively. These expenses are related to our increased activities in the Gulf of Mexico, including our three Dutch wells which are producing, drilling Mary Rose #2, and bringing Mary Rose #1 and Mary Rose #3 to production.

Exploration Expense. We reported $4.3 million of exploration expenses for the three months ended March 31, 2008. Of this amount, approximately $4.0 million was related to dry hole costs for High Island A198. The remaining costs are attributable to various geological and geophysical activities, seismic data, and delay rentals. For the three months ended March 31, 2007, we reported $0.3 million of exploration expenses. These costs are attributable to the cost of various geological and geophysical activities, seismic data, and delay rentals.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months ended March 31, 2008 was approximately $4.1 million. For the three months ended March 31, 2007, we recorded $0.8 million of depreciation, depletion and amortization. The increase is the result of production from our Dutch #2 well which began producing in July 2007 and our Dutch #3 well which began producing in November 2007.

Impairment of Natural Gas and Oil Properties. For the three months ended March 31, 2008, the Company recorded an impairment charge of $837,098. Of this amount, $245,361 relates to the expiration of two lease blocks; Vioska Knoll 167 and Vermillion 231, and $591,737 relates to the Company’s 4,000 net mineral acres in the West Texas Barnett Shale play in Jeff Davis and Reeves Counties, Texas. No impairment of natural gas and oil properties was incurred during the three months ended March 31, 2007.

General and Administrative Expenses. General and administrative expenses for the three months ended March 31, 2008 and the three months ended March 31, 2007 were approximately $2.2 million and $2.4 million, respectively.

Major components of general and administrative expenses for the three months ended March 31, 2008 included approximately $1.0 million in salaries and benefits, approximately $0.3 million in legal, accounting, engineering and other professional fees, $0.3 million in office administration expenses, $0.1 million in insurance costs, and $0.5 million related to the cost of expensing stock options and stock grant compensation.

Major components of general and administrative expenses for the three months ended March 31, 2007 included approximately $1.2 million in salaries and benefits, $0.1 million in legal, accounting, engineering and other professional fees, $0.5 million in office administration expenses, and $0.6 million related to the cost of expensing stock options and stock grant compensation.

Interest Expense. We reported interest expense of approximately $1.4 million for the three months ended March 31, 2008, compared to interest expense of approximately $0.7 million for the three months ended March 31, 2007. The higher level of interest expense is attributable to higher levels of bank debt outstanding by the Company and its affiliates during such period.

Interest Income. We reported interest income of approximately $0.9 million for the three months ended March 31, 2008. This compares to approximately $0.2 million of interest income reported for the three months ended March 31, 2007. The increase is due to additional interest income from loans made to affiliates.

Gain (Loss) on Sale of Assets and Other. For the three months ended March 31, 2008, we reported a gain on sale of assets and other of approximately $59.9 million. Of this amount, approximately $63.4 million relates to the gain on the sale of the Company’s 10% limited partnership interest in Freeport LNG, offset by a $2.9 million loss recognized on the sale of certain assets held by CVCC and a $0.6 million loss when the Company wrote down its investment in Moblize. For the three months ended March 31, 2007, we reported a loss on sale of assets and other of approximately $0.7 million resulting from the Company’s December 2006 sale of COI’s 25% working interest in the Grand Isle 75 well (“Liberty”).

Nine Months Ended March 31, 2008 Compared to Nine Months Ended March 31, 2007

Natural Gas, Oil and NGL Sales. We reported revenues of approximately $47.3 million for the nine months ended March 31, 2008, compared to revenues of approximately $6.2 million for the nine months ended March 31, 2007. This increase is mainly attributable to our Dutch #2 discovery which began producing in July 2007 and our Dutch #3 discovery which began producing in November 2007, as well as a general increase in prices for natural gas, oil and condensate.

For the nine months ended March 31, 2008, the price of natural gas was $7.69 per Mcf while the price for oil and condensate was $87.22 per barrel and the price for NGLs was $1.45 per gallon. For the nine months ended March 31, 2007, the price of natural gas was $7.55 per Mcf while the price for oil and condensate was $59.81 per barrel. The Company did not have a material quantity of NGL sales for the nine months ended March 31, 2007.

Natural Gas, Oil and NGL Production and Average Sales Prices. Our net natural gas production for the nine months ended March 31, 2008 was approximately 16.9 Mmcf/d, up from approximately 3.3 Mmcf/d for the nine months ended March 31, 2007. Net oil and condensate production for the comparable periods also increased from approximately 100 barrels per day to approximately 300 barrels per day. Our NGL production for the three months ended March 31, 2008 was approximately 8,100 gallons per day. This increase in natural gas, oil and NGL production is principally attributable to Dutch #2 which began producing in July 2007 and Dutch #3 which began producing in November 2007.

Operating Expenses. Lease operating expenses for the nine months ended March 31, 2008 and the nine months ended March 31, 2007 were approximately $3.2 million and $0.3 million, respectively. These expenses are related to increased activity in the Gulf of Mexico, including drilling, completing and producing from our three Dutch wells, drilling three Mary Rose wells, and bringing Mary Rose #1 and Mary Rose #3 to production.

Exploration Expense. We reported approximately $5.2 million of exploration expenses for the nine months ended March 31, 2008. Of this amount, approximately $4.0 million was related to dry hole costs for High Island A198. The remaining costs are attributable to various geological and geophysical activities, seismic data, and delay rentals. For the nine months ended March 31, 2007, we reported approximately $1.1 million of exploration expenses. These costs are attributable to the cost of various geological and geophysical activities, seismic data, and delay rentals.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the nine months ended March 31, 2008 was approximately $6.0 million. For the nine months ended March 31, 2007, we recorded approximately $1.0 million of depreciation, depletion and amortization. The increase is the result of production from our Dutch #2 well which began producing in July 2007 and our Dutch #3 well which began producing in November 2007.

Impairment of Natural Gas and Oil Properties. For the nine months ended March 31, 2008, the Company recorded an impairment charge of $837,098. Of this amount, $245,361 relates to the expiration of two lease blocks;

Vioska Knoll 167 and Vermillion 231, and $591,737 relates to the Company’s 4,000 net mineral acres in the West Texas Barnett Shale play in Jeff Davis and Reeves Counties, Texas. Approximately $0.2 million of impairment was reported for the nine months ended March 31, 2007. This was attributable to a write-down of costs of the Alta-Ellis #1 well in December 2006.

General and Administrative Expenses. General and administrative expenses for the nine months ended March 31, 2008 and the nine months ended March 31, 2007 were approximately $5.3 million and $4.9 million, respectively.

Major components of general and administrative expenses for the nine months ended March 31, 2008 included approximately $2.3 million in salaries and benefits, approximately $0.9 million in legal, accounting, engineering and other professional fees, approximately $0.4 million in office administration expenses, $0.3 million in insurance costs, and $1.4 million related to the cost of expensing stock options and stock grant compensation.

Major components of general and administrative expenses for the nine months ended March 31, 2007 included approximately $2.1 million in salaries and benefits, $0.4 million in legal, accounting, engineering and other professional fees, $1.1 million in office administration expenses, $0.2 million in insurance costs, and $1.1 million related to the cost of expensing stock options and stock grant compensation.

Interest Expense. We reported interest expense of approximately $3.6 million for the nine months ended March 31, 2008, compared to interest expense of $1.3 million for the nine months ended March 31, 2007. The higher level of interest expense is attributable to higher levels of bank debt outstanding by the Company and its affiliates during such period.

Interest Income. We reported interest income of approximately $1.8 million for the nine months ended March 31, 2008. This compares to $0.6 million of interest income reported for the nine months ended March 31, 2007. The increase is due to additional interest income from loans made to affiliates.

Gain (Loss) on Sale of Assets and Other. For the nine months ended March 31, 2008, we reported a gain on sale of assets and other of approximately $62.0 million. Of this amount, approximately $63.4 million relates to the gain on the sale of the Company’s 10% limited partnership interest in Freeport LNG, $2.1 relates to a payment from a stockholder related to a short swing profit liability, offset by a $2.9 million loss recognized on the sale of certain assets held by CVCC and a $0.6 million loss when the Company wrote down its investment in Moblize. For the nine months ended March 31, 2007, we reported a loss on sale of assets and other of approximately $2.0 million resulting from the Company’s December 2006 sale of COI’s 25% working interest in the Grand Isle 72 well (“Liberty”).

Production, Prices, Operating Expenses, and Other


	Three Months Ended				Nine Months Ended
	March 31,				March 31,
	2008		2007		2008		2007
	(Dollar amounts in 000’s,				(Dollar amounts in 000’s,
	except per Mcfe amounts)				except per Mcfe amounts)
Production Data:
Natural gas (million cubic feet)		1,555		499		4,651		687
Oil and condensate (thousand barrels)		38		12		95		17
Natural gas liquids (thousand gallons)		1,403		*		2,218		*

Total (million cubic feet equivalent)		1,983		571		5,538		789

Natural gas (million cubic feet per day)		17.1		5.5		16.9		2.5
Oil and condensate (thousand barrels per day)		0.4		0.1		0.3		0.1
Natural gas liquids (thousand gallons per day)		15.4		*		8.1		*

Total (million cubic feet equivalent per day)		21.7		6.1		19.9		3.1

Average Sales Price:
Natural gas (per thousand cubic feet)	$	7.35	$	7.75	$	7.69	$	7.55
Oil and condensate (per barrel)	$	102.48	$	56.20	$	87.22	$	59.81
Natural gas liquids (per gallon)	$	1.56		*	$	1.45		*

Selected data per Mcfe:
Lease operating expenses	$	0.75	$	0.19	$	0.57	$	0.38
General and administrative expenses	$	1.12	$	4.17	$	0.96	$	6.21
Depreciation, depletion and amortization of natural gas and oil properties	$	2.00	$	1.15	$	1.01	$	1.28


*		Not meaningful

Capital Resources and Liquidity

The Company views periodic reserve sales as an opportunity to capture value, reduce reserve and price risk, in addition to being a source of funds for potentially higher rate of return natural gas and oil exploration investments. We believe these periodic natural gas and oil property sales are an efficient strategy to meet our cash and liquidity needs by providing us with immediate cash, which would otherwise take years to realize through the production lives of the fields sold. We have in the past and expect in the future to continue to rely heavily on the sales of assets to generate cash to fund our exploration investments and operations.

These sales bring forward future revenues and cash flows, but our longer term liquidity could be impaired to the extent our exploration efforts are not successful in generating new discoveries, production, revenues and cash flows. Additionally, our longer term liquidity could be impaired due to the decrease in our inventory of producing properties that could be sold in future periods. Further, as a result of these property sales the Company’s ability to collateralize bank borrowings is reduced which increases our dependence on more expensive mezzanine debt and potential equity sales. The availability of such funds will depend upon prevailing market conditions and other factors over which we have no control, as well as our financial condition and results of operations.

Operating Activities. Cash flows provided by operating activities for the nine months ended March 31, 2008 were approximately $66.4 million, compared to cash flows used in operating activities of approximately $5.8

million for the nine months ended March 31, 2007. This increase in cash flows provided by operating activities is primarily attributable to increased natural gas and oil production and revenues from our Dutch #2 discovery which began producing in July 2007 and our Dutch #3 discovery which began producing in November 2007.

Investing Activities. Cash flows used in investing activities for the nine months ended March 31, 2008 were approximately $31.7 million, compared to $30.1 million for the same period in 2007. This $1.6 million increase in capital expenditures is primarily attributable to purchasing additional working interests in our Dutch and Mary Rose discoveries and investing more in natural gas and oil properties, offset by proceeds received from the sale of our Arkansas Fayetteville Shale, our 10% limited partnership interest in Freeport LNG and certain assets held by CVCC.

Financing Activities. Our financing activities used approximately $15.5 million in cash flow for the nine months ended March 31, 2008 compared to providing $28.3 million for the same period in 2007. This difference of $43.8 million is primarily attributable to prepaying $40.0 million of long term debt and purchasing $5.9 million of equity and options, offset by additional borrowings by our affiliates.

Capital Budget. For the remaining nine months of 2008, our capital expenditure budget calls for us to invest approximately $29.0 million as we complete and bring Mary Rose #2 to production, drill and complete Mary Rose #4, complete our platform at Eugene Island 11 and its associated pipeline and drill a wildcat exploration well (“Eloise”) to a deeper horizon on our Mary Rose acreage.

The following capital expenditure descriptions are for the Company and its wholly-owned subsidiaries only, and do not include the capital expenditure descriptions for our partially-owned REX subsidiary.

Of the $29.0 million in offshore capital expenditures budgeted for the next nine months, we have budgeted to invest approximately $8.4 million to complete Mary Rose #2, approximately $8.5 million of remaining costs to drill and complete Mary Rose #4, approximately $7.1 million in remaining platform and pipeline costs, and approximately $3.1 million to drill Eloise. We have also budgeted to spend approximately $1.9 million in delay rentals and miscellaneous costs on Grand Isle 72 and High Island A198.

Contango or our partially owned subsidiary, REX, may need to raise additional debt and/or equity capital to supplement our internally generated cash flow to fund our offshore exploration and development program. There can be no assurance we or REX will be able to raise such additional capital.

Natural Gas and Oil Reserves

The following table presents our estimated net proved, developed producing natural gas and oil reserves and the pre-tax net present value of our reserves at March 31, 2008. Our onshore reserves were based on a reserve report generated by W.D. Von Gonten & Co. The offshore reserves were based on a reserve report generated by William M. Cobb & Associates, Inc. The pre-tax net present value is not intended to represent the current market value of the estimated natural gas and oil reserves we own.

The pre-tax net present value of future cash flows attributable to our proved reserves as of March 31, 2008 was determined by the March 31, 2008 prices of $9.37 per MMbtu for natural gas at Henry Hub and $101.58 per barrel of oil at West Texas Intermediate Posting, in each case before adjustments.


	Proved
	Reserves as of
	March 31, 2008
Natural Gas (MMcf)		189,326
Oil, Condensate and Natural Gas Liquids (MBbls)		8,140
Total proved reserves (Mmcfe)		238,166

Pre-tax net present value, SEC guidelines ($000)	$	1,753,849

The process of estimating natural gas and oil reserves is complex. It requires various assumptions, including natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Our third party engineers must project production rates and timing of development expenditures, as well as analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. Therefore, estimates of natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from estimates. Any significant variance could materially affect the estimated quantities and net present value of reserves. In addition, our third party engineers may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control. Because most of our reserve estimates are not based on a lengthy production history and are calculated using volumetric analysis, these estimates are less reliable than estimates based on a lengthy production history.

It should not be assumed that the pre-tax net present value is the current market value of our estimated natural gas and oil reserves. In accordance with requirements of the Securities and Exchange Commission, we base the estimated discounted future net cash flows from proved reserves on prices and costs available on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Credit Facility

On February 5, 2008, using the proceeds from our $68.0 million sale of Freeport LNG, the Company prepaid the $20.0 million outstanding under its three-year $20.0 million secured term loan facility with The Royal Bank of Scotland plc (the “RBS Facility”) and terminated the RBS Facility. At the time of prepayment and termination, the Company was in compliance with its financial covenants, ratios and other provisions. In addition to the $20.0 million in principal, the Company paid $342,292 in accrued but unpaid interest and prepayment penalties.

On February 5, 2008, the Company used additional proceeds from its $68.0 million sale of Freeport LNG and prepaid the $20.0 million outstanding under its $60.0 million secured term loan agreement with a private investment firm (the “Term Loan Agreement”). The Company now has $60.0 million in unused borrowing availability. The Term Loan Agreement is secured with substantially all the assets of the Company. Borrowings under the Term Loan Agreement bear interest at 30 day LIBOR plus 5.0%. Accrued interest is due monthly. The Term Loan Agreement matures on June 30, 2009, but amounts borrowed may be prepaid at any time with no prepayment penalty. We pay a non-use fee in the amount of 1.50% per annum multiplied by such non-funded amount.

The Term Loan Agreement requires a minimum level of working capital and contains certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell certain assets, and pay dividends. Failure to maintain required working capital or comply with certain covenants in the Term Loan Agreement could result in a default and acceleration of all indebtedness under such credit facilities, as well as limit our ability to borrow additional funds. As of March 31, 2008, the Company was in compliance with its financial covenants, ratios and other provisions of the Term Loan Agreement.

Risk Factors

In addition to the other information set forth elsewhere in this Form 10-Q and in our annual report on Form 10-K, you should carefully consider the following factors when evaluating the Company. An investment in the Company is subject to risks inherent in our business. The trading price of the shares of the Company is affected by the performance of our business relative to, among other things, competition, market conditions and general economic and industry conditions. The value of an investment in the Company may decrease, resulting in a loss. The risk factors listed below are not all inclusive.

We have no ability to control the prices that we receive for natural gas and oil. Natural gas and oil prices fluctuate widely, and low prices would have a material adverse effect on our revenues, profitability and growth.

Our revenues, profitability and future growth depend significantly on natural gas and crude oil prices. Prices received affect the amount of future cash flow available for capital expenditures and repayment of indebtedness and our ability to raise additional capital. Lower prices may also affect the amount of natural gas and oil that we can economically produce. Factors that can cause price fluctuations include:

	•		The domestic and foreign supply of natural gas and oil.

	•		Overall economic conditions.

	•		The level of consumer product demand.

	•		Adverse weather conditions and natural disasters.

	•		The price and availability of competitive fuels such as heating oil and coal.

	•		Political conditions in the Middle East and other natural gas and oil producing regions.

	•		The level of LNG imports.

	•		Domestic and foreign governmental regulations.

	•		Potential price controls and special taxes.

	•		Access to pipelines and gas processing plants.

We depend on the services of our chairman, chief executive officer and chief financial officer, and implementation of our business plan could be seriously harmed if we lost his services.

We depend heavily on the services of Kenneth R. Peak, our chairman, chief executive officer, and chief financial officer. We do not have an employment agreement with Mr. Peak, and the proceeds from a $10.0 million “key person” life insurance policy on Mr. Peak may not be adequate to cover our losses in the event of Mr. Peak’s death.

We are highly dependent on the technical services provided by our alliance partners and could be seriously harmed if our alliance agreements were terminated.

Because we have only six employees, none of whom are geoscientists or petroleum engineers, we are dependent upon alliance partners for the success of our natural gas and oil exploration projects and expect to remain so for the foreseeable future. Highly qualified explorationists and engineers are difficult to attract and retain. As a result, the loss of the services of one or more of our alliance partners could have a material adverse effect on us and could prevent us from pursuing our business plan. Additionally, the loss by our alliance partners of certain explorationists could have a material adverse effect on our operations as well.

Our ability to successfully execute our business plan is dependent on our ability to obtain adequate financing.

Our business plan, which includes participation in 3-D seismic shoots, lease acquisitions, the drilling of exploration prospects and producing property acquisitions, has required and is expected to continue to require substantial capital expenditures. We may require additional financing to fund our planned growth. Our ability to raise additional capital will depend on the results of our operations and the status of various capital and industry markets at the time we seek such capital. Accordingly, we cannot be certain that additional financing will be available to us on acceptable terms, if at all. In particular, our credit facility imposes limits on our

ability to borrow under the facility based on adjustments to the value of our hydrocarbon reserves, and our credit facility limits our ability to incur additional indebtedness. In the event additional capital resources are unavailable, we may be required to curtail our exploration and development activities or be forced to sell some of our assets in an untimely fashion or on less than favorable terms.

We frequently obtain capital through the sale of our producing properties.

The Company, since its inception in September 1999, has raised approximately $483.0 million in proceeds from 10 separate property sales. These sales bring forward future revenues and cash flows, but our longer term liquidity could be impaired to the extent our exploration efforts are not successful in generating new discoveries, production, revenues and cash flows. Additionally, our longer term liquidity could be impaired due to the decrease in our inventory of producing properties that could be sold in future periods. Further, as a result of these property sales the Company’s ability to collateralize bank borrowings is reduced which increases our dependence on more expensive mezzanine debt and potential equity sales. The availability of such funds will depend upon prevailing market conditions and other factors over which we have no control, as well as our financial condition and results of operations.

We assume additional risk as Operator in drilling high pressure wells in the Gulf of Mexico.

Contango Operators, Inc. (“COI”) is a wholly-owned subsidiary of the Company, formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico. COI is currently the operator for our Dutch and Mary Rose discoveries. Although as a Company we have previously taken working interests in offshore prospects, our recent exploration discoveries are the first wells in which we have assumed the role of operator. Estimated drilling costs could be significantly higher if we encounter difficulty in drilling offshore exploration wells.

Drilling activities are subject to numerous risks, including the significant risk that no commercially productive hydrocarbon reserves will be encountered. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. The Company’s drilling operations may be curtailed, delayed, canceled or negatively impacted as a result of numerous factors, including inexperience as an operator, title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery or availability of material, equipment and fabrication yards. In periods of increased drilling activity resulting from high commodity prices, demand exceeds availability for drilling rigs, drilling vessels, supply boats and personnel experienced in the oil and gas industry in general, and the offshore oil and gas industry in particular. This may lead to difficulty and delays in consistently obtaining certain services and equipment from vendors, obtaining drilling rigs and other equipment at favorable rates and scheduling equipment fabrication at factories and fabrication yards. This, in turn, may lead to projects being delayed or experiencing increased costs. The cost of drilling, completing, and operating wells is often uncertain, and we cannot assure that new wells will be productive or that we will recover all or any portion of our investment. The risk of significant cost overruns, curtailments, delays, inability to reach our target reservoir and other factors detrimental to drilling and completion operations may be higher due to our inexperience as an operator.

Most of our revenues and production are from our Dutch wells and we depend upon outside third parties to operate and maintain our production, pipelines and processing facilities.

We depend upon the services of others to drill and complete our wells, and operate production platforms, pipelines, gas processing facilities and the infrastructure required to produce and market our natural gas, condensate and oil. As a result, we have no control over how frequently and how long our production is shut-in when production problems, weather and other production shut-ins occur. As we have ramped up production at our three Dutch wells, we have had to increase the production handling capacity of related downstream infrastructure necessary to produce these wells at their designed flow rates. As a consequence, we have incurred a number of production shut-ins which have negatively affected our near term revenues and cash flow.

Repeated production shut-ins can possibly damage our well bores.

Our Dutch #1, #2 and #3 well bores are required to be shut-in from time to time due to a combination of weather, mechanical problems and shut-ins necessary to upgrade and increase the production handling capacity at related downstream platform, gas processing and pipeline infrastructure. In addition to negatively impacting our

near term revenues and cash flow, repeated production shut-ins could have the potential to damage our well bores if repeated excessively or not executed properly. The loss of a well bore due to damage could require us to drill additional wells to recover our reserves.

We are highly dependent on the lending availability of a single company.

Our $60.0 million Term Loan Agreement is with a private investment firm. Should the private investment firm encounter difficulties funding future requested advances, some portion or all of the capital that remains unfunded may no longer be available. In that case, we would be forced to seek alternative and possibly more expensive financing, which may or may not be available.

We have outsourced the marketing of our production and the vast majority of our revenues are from one purchaser, Cokinos Energy Corporation.

A significant portion of the Company’s production is sold to Cokinos Energy Corporation. These sales to Cokinos Energy Corporation are secured with letters of credit.

Our capital exploration is focused on highly capital intensive prospect areas which increase our risk of incurring significant losses.

We continue to increase our capital investments in the offshore Gulf of Mexico, which represents a major increase in the risk profile of the Company.

Natural gas and oil reserves are depleting assets and the failure to replace our reserves would adversely affect our production and cash flows.

Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace reserves, our level of production and cash flows would be adversely impacted. Production from natural gas and oil properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Further, the majority of our reserves are proved developed producing. Accordingly, we do not have significant opportunities to increase our production from our existing proved reserves. Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. If we are not successful, our future production and revenues will be adversely affected.

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

The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this report.

In order to prepare these estimates, our independent third party petroleum engineers must project production rates and timing of development expenditures as well as analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of natural gas and oil reserves are inherently imprecise.

Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves shown

in this report. In addition, estimates of our proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control. Most of the producing wells included in our reserve report have produced for a relatively short period of time. Because some of our reserve estimates are not based on a lengthy production history and are calculated using volumetric analysis, these estimates are less reliable than estimates based on a more lengthy production history.

You should not assume that the pre-tax net present value of our proved reserves prepared in accordance with Securities and Exchange Commission guidelines referred to in this report is the current market value of our estimated natural gas and oil reserves. We base the pre-tax net present value of future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices, costs, taxes and the volume of produced reserves will likely differ materially from those used in the pre-tax net present value estimate.

The proved reserves assigned to our Dutch and Mary Rose discoveries have only five producing well bores that, as of April 30, 2008, had only fifteen months of production history. Reserve assessments based on only five well bores with limited production history are subject to greater risk of downward revision than multiple well bores from a mature producing reservoir.

We rely on the accuracy of the estimates in the reservoir engineering reports provided to us by our outside engineers.

We have no in house reservoir engineering capability, and therefore rely on the accuracy of the periodic reservoir reports provided to us by our independent third party reservoir engineers. If those reports prove to be inaccurate, our financial reports could have material misstatements. Further, we use the reports of our independent reservoir engineers in our financial planning. If the reports of the outside reservoir engineers prove to be inaccurate, we may make misjudgments in our financial planning.

Exploration is a high risk activity, and our participation in drilling activities may not be successful.

Our future success will largely depend on the success of our exploration drilling program. Participation in exploration drilling activities involves numerous risks, including the significant risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells is uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

	•		Unexpected drilling conditions.

	•		Blowouts, fires or explosions with resultant injury, death or environmental damage.

	•		Pressure or irregularities in formations.

	•		Equipment failures or accidents.

	•		Tropical storms, hurricanes and other adverse weather conditions.

	•		Compliance with governmental requirements and laws, present and future.

	•		Shortages or delays in the availability of drilling rigs and the delivery of equipment.

	•		Our turnkey drilling contracts reverting to a day rate contract which would significantly increase the cost and risk to the Company.

	•		Problems at third party operated platforms, pipelines and gas processing facilities over which we have no control.

Even when properly used and interpreted, 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. Poor results from our drilling activities would materially and adversely affect our future cash flows and results of operations.

In addition, as a “successful efforts” company, we choose to account for unsuccessful exploration efforts (the drilling of “dry holes”) and seismic costs as a current expense of operations, which immediately impacts our earnings. Significant expensed exploration charges in any period would materially adversely affect our earnings for that period and cause our earnings to be volatile from period to period.

The natural gas and oil business involves many operating risks that can cause substantial losses.

The natural gas and oil business involves a variety of operating risks, including:

	•		Blowouts, fires and explosions.

	•		Surface cratering.

	•		Uncontrollable flows of underground natural gas, oil or formation water.

	•		Natural disasters.

	•		Pipe and cement failures.

	•		Casing collapses.

	•		Stuck drilling and service tools.

	•		Abnormal pressure formations.

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

	•		Capacity constraints, equipment malfunctions and other problems at third party operated platforms, pipelines and gas processing plants over which we have no control.

	•		Repeated shut-ins of our well bores could significantly damage our well bores.

If any of the above events occur, we could incur substantial losses as a result of:

	•		Injury or loss of life.

	•		Reservoir damage.

	•		Severe damage to and destruction of property or equipment.

	•		Pollution and other environmental damage.

	•		Clean-up responsibilities.

	•		Regulatory investigations and penalties.

	•		Suspension of our operations or repairs necessary to resume operations.

Offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as capsizing and collisions. In addition, offshore operations, and in some instances, operations along the Gulf Coast, are subject to damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce the funds available for exploration, development or leasehold acquisitions, or result in loss of properties.

If we were to experience any of these problems, it could affect well bores, platforms, gathering systems and processing facilities, any one of which could adversely affect our ability to conduct operations. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks. Losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. We may not be able to maintain adequate insurance in the future at rates we consider reasonable, and particular types of coverage may not be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

Not hedging our production may result in losses.

Due to the significant volatility in natural gas prices and the potential risk of significant hedging losses if our production should be shut-in during a period when NYMEX natural gas prices increase, our policy is to hedge only through the purchase of puts. By not hedging our production, we may be more adversely affected by declines in natural gas and oil prices than our competitors who engage in hedging arrangements.

Our ability to market our natural gas and oil may be impaired by capacity constraints and equipment malfunctions on the platforms, gathering systems, pipelines and gas plants that transport and process our natural gas and oil.

All of our natural gas and oil is transported through gathering systems, pipelines and processing plants, and in some cases offshore platforms, which we do not own. Transportation capacity on gathering system pipelines and platforms is occasionally limited and at times unavailable due to repairs or improvements being made to these

facilities or due to capacity being utilized by other natural gas or oil shippers that may have priority transportation agreements. If the gathering systems, processing plants, platforms or our transportation capacity is materially restricted or is unavailable in the future, our ability to market our natural gas or oil could be impaired and cash flow from the affected properties could be reduced, which could have a material adverse effect on our financial condition and results of operations. Further, repeated shut-ins of our wells could result in damage to our well bores that would impair our ability to produce from these wells and could result in additional wells being required to produce our reserves.

We have no assurance of title to our leased interests.

Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is to not incur the expense of retaining title lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we rely upon the judgment of our alliance partners to perform the field work in examining records in the appropriate governmental, county or parish clerk’s office before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to the drilling of an exploration well the operator of the well will typically obtain a preliminary title review of the drillsite lease and/or spacing unit within which the proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible. We have no assurance, however, that any such deficiencies have been cured by the operator of any such wells. It does happen, from time to time, that the examination made by title lawyers reveals that the lease or leases are invalid, having been purchased in error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we may not be able to proceed with our exploration and development of the lease site or may incur costs to remedy a defect. It may also happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion.

Competition in the natural gas and oil industry is intense, and we are smaller and have a more limited operating history than many of our competitors.

We compete with a broad range of natural gas and oil companies in our exploration and property acquisition activities. We also compete for the equipment and labor required to operate and to develop these properties. Most of our competitors have substantially greater financial resources than we do. These competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties. Further, they may be able to evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and oil and to acquire additional properties in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of our competitors have been operating for a much longer time than we have and have substantially larger staffs. We may not be able to compete effectively with these companies or in such a highly competitive environment.

We are subject to complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment. Failure to comply with such rules and regulations could result in substantial penalties and have an adverse effect on us. These laws and regulations may:

	•		Require that we obtain permits before commencing drilling.

	•		Restrict the substances that can be released into the environment in connection with drilling and production activities.

	•		Limit or prohibit drilling activities on protected areas, such as wetlands or wilderness areas.

	•		Require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells.

Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain only limited insurance coverage for sudden and accidental environmental damages. Accordingly, we may be subject to

liability, or we may be required to cease production from properties in the event of environmental damages. These laws and regulations have been changed frequently in the past. In general, these changes have imposed more stringent requirements that increase operating costs or require capital expenditures in order to remain in compliance. It is also possible that unanticipated factual developments could cause us to make environmental expenditures that are significantly different from those we currently expect. Existing laws and regulations could be changed and any such changes could have an adverse effect on our business and results of operations.

We cannot control the activities on properties we do not operate.

Other companies currently operate properties in which we have an interest. As a result, we have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors that are outside of our control, including:

	•		Timing and amount of capital expenditures.

	•		The operator’s expertise and financial resources.

	•		Approval of other participants in drilling wells.

	•		Selection of technology.

Acquisition prospects are difficult to assess and may pose additional risks to our operations.

We expect to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considers favorable. The successful acquisition of natural gas and oil properties requires an assessment of:

	•		Recoverable reserves.

	•		Exploration potential.

	•		Future natural gas and oil prices.

	•		Operating costs.

	•		Potential environmental and other liabilities and other factors.

	•		Permitting and other environmental authorizations required for our operations.

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

Future acquisitions could pose additional risks to our operations and financial results, including:

	•		Problems integrating the purchased operations, personnel or technologies.

	•		Unanticipated costs.

	•		Diversion of resources and management attention from our exploration business.

	•		Entry into regions or markets in which we have limited or no prior experience.

	•		Potential loss of key employees, particularly those of the acquired organization.

Anti-takeover provisions of our certificate of incorporation, bylaws and Delaware law could adversely effect a potential acquisition by third parties that may ultimately be in the financial interests of our stockholders.

Our certificate of incorporation, bylaws and the Delaware General Corporation Law contain provisions that may discourage unsolicited takeover proposals. These provisions could have the effect of inhibiting fluctuations in the market price of our common stock that could result from actual or rumored takeover attempts, preventing changes in our management or limiting the price that investors may be willing to pay for shares of common stock. These provisions, among other things, authorize the board of directors to:

	•		Designate the terms of and issue new series of preferred stock.

	•		Limit the personal liability of directors.

	•		Limit the persons who may call special meetings of stockholders.

	•		Prohibit stockholder action by written consent.

	•		Establish advance notice requirements for nominations for election of the board of directors and for proposing matters to be acted on by stockholders at stockholder meetings.

	•		Require us to indemnify directors and officers to the fullest extent permitted by applicable law.

	•		Impose restrictions on business combinations with some interested parties.

Our common stock is thinly traded.

Contango has approximately 16.6 million shares of common stock outstanding, held by approximately 150 holders of record. Directors and officers own or have voting control over approximately 3.3 million shares. Since our common stock is thinly traded, the purchase or sale of relatively small common stock positions may result in disproportionately large increases or decreases in the price of our common stock.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate and Credit Rating Risks. As of March 31, 2008, we had approximately $25.4 million in cash and cash equivalents, of which approximately $16.1 million was invested in highly liquid AAA-rated tax exempt money market funds. We consider all highly liquid debt instruments having an original maturity of 90 days or less to be cash equivalents.

Investments in fixed-rate, interest-earning instruments carry a degree of interest rate and credit rating risk. Fixed-rate securities may have their fair market value adversely impacted because of changes in interest rates and credit ratings. Additionally, the value of our investments may be impaired temporarily or permanently. Due in part to these factors, our investment income may decline and we may suffer losses in principal. Currently, we do not use any derivative or other financial instruments or derivative commodity instruments to hedge any market risks, including changes in interest rates or credit ratings, and we do not plan to employ these instruments in the future. Because of the nature of the issuers of the securities that we invest in, we do not believe that we have any cash flow exposure arising from changes in credit ratings. Based on a sensitivity analysis performed on the financial instruments held as of March 31, 2008, an immediate 10% change in interest rates is not expected to have a material effect on our near-term financial condition or results of operations.

Commodity Risk. Our major commodity price risk exposure is to the prices received for our natural gas and oil production. Realized commodity prices received for our production are the spot prices applicable to natural gas and crude oil. Prices received for natural gas and oil are volatile and unpredictable and are beyond our control. For the three months ended March 31, 2008, a 10% fluctuation in the prices received for natural gas and oil production would impact our revenues by approximately $2.1 million. It could also lead to impairment of our natural gas and oil properties.

Item 4. Controls and Procedures

Kenneth R. Peak, our Chairman, Chief Executive Officer and Chief Financial Officer, together with our Controller and Treasurer, carried out an evaluation of the effectiveness of the Company’s “disclosure controls and

procedures” as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of March 31, 2008. Based upon that evaluation, the Company’s management concluded that, as of March 31, 2008, the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by us in 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, and to ensure that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chairman, Chief Executive Officer, Chief Financial Officer, Controller and Treasurer, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in the Company’s internal control over financial reporting that occurred during the fiscal quarter ended March 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1A. Risk Factors

The description of the risk factors associated with the Company set forth under the heading “Risk Factors” in Item 2 of Part I, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of this Form 10-Q are incorporated into this Item 1A by reference and supersede the description of risk factors set forth under the heading “Risk Factors” in Item 1 of Part I of our annual report on Form 10-K.

Item 6. Exhibits

(a) Exhibits:

The following is a list of exhibits filed as part of this Form 10-Q. Where so indicated by a footnote, exhibits, which were previously filed, are incorporated herein by reference.


Exhibit
Number		Description
	2.1	Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and REX Offshore Corporation, dated as of September 1, 2005. (1)

	2.2	Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and COE Offshore, LLC dated as of September 1, 2005. (1)

	2.3	Purchase and Sale Agreement between Contango STEP, LP and Rosetta Resources Operating LP, dated April 28, 2006. (2)

	2.4	Purchase and Sale Agreement between Contango Operators, Inc. and Rosetta Resources Offshore LLC, dated December 14, 2006. (3)

	2.5	Asset Purchase Agreement by and among Petrohawk Energy Corporation and Contango Operators Inc. (successor-in-interest to Contango Gas Solutions, L.P.), Alta Resources, L.L.C., GPM Energy, LLC, MND Partners, L.P. and TePee Petroleum Company, Inc., dated as of November 26, 2007. (4)

	2.7	Asset Purchase Agreement by and among XTO Energy Inc. and Contango Operators, Inc., Alta Resources, L.L.C., GPM Energy, LLC, MND Partners, L.P. and TePee Petroleum Company, Inc., dated as of January 4, 2008. (5)

	2.8	Partnership Interest Purchase Agreement by and among Turbo LNG LLC, Contango Sundance, Inc. and Osaka Gas Co., Ltd., as Guarantor, dated January 7, 2008. (6)

	3.1	Certificate of Incorporation of Contango Oil & Gas Company. (7)

	3.2	Bylaws of Contango Oil & Gas Company. (7)

	3.3	Agreement of Plan of Merger of Contango Oil & Gas Company, a Delaware corporation, and Contango Oil & Gas Company, a Nevada corporation. (7)

	3.4	Amendment to the Certificate of Incorporation of Contango Oil & Gas Company. (8)

	4.1	Facsimile of common stock certificate of Contango Oil & Gas Company. (9)

	4.2	Certificate of Designations, Preferences and Relative Rights and Limitations for Series E Perpetual Cumulative Convertible Preferred Stock of Contango Oil & Gas Company. (10)


Exhibit
Number		Description
	4.3	Securities Purchase Agreement, dated as of May 11, 2007, among Contango Oil & Gas Company and the Purchasers named therein, relating to the Series E Perpetual Cumulative Convertible Preferred Stock. (10)

	10.1	Assignment of Operating Rights Interest between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.2	Partial Assignment of Oil and Gas Leases between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.3	Assignment of Operating Rights Interest between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.4	Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.5	Partial Assignment of Oil and Gas Leases between Olympic Energy Partners, LLC and Contango Operators, Inc. dated as of January 3, 2008. (11)

	10.6	Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.7	Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.8	Partial Assignment of Oil and Gas Leases between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.9	Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.10	Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008. (12)

	10.11	Partial Assignment of Oil and Gas Leases between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008. (12)

	10.12	Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008. (12)

	10.13	Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of April 3, 2008. (12)

	10.14	Partial Assignment of Oil and Gas Leases between Olympic Energy Partners, LLC and Contango Operators, Inc. dated as of April 3, 2008. (12)

	10.15	Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of April 3, 2008. (12)

	10.16	Amended and Restated Limited Liability Company Agreement of Republic Exploration LLC, dated April 1, 2008. (12)

	10.17	Third Amendment to Term Loan Agreement, dated as of January 17, 2008, between Contango Oil & Gas Company, as Borrower, and Centaurus Capital LLC, as Lender. (13)

	10.18	Fourth Amendment to Term Loan Agreement, dated as of February 13, 2008, between Contango Oil & Gas Company, as Borrower, and Centaurus Capital LLC, as Lender. †

	23.2	Consent of William M. Cobb & Associates, Inc. †

	31.1	Certification required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934. †

	32.1	Certification pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. †


†		Filed herewith.

1.		Filed as an exhibit to the Company’s report on Form 8-K, dated September 2, 2005, as filed with the Securities and Exchange Commission on September 8, 2005.

2.		Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended March 31, 2006, dated May 15, 2006, as filed with the Securities and Exchange Commission.

3.		Filed as an exhibit to the Company’s report on Form 8-K, dated December 14, 2006, as filed with the Securities and Exchange Commission on December 20, 2006.


4.		Filed as an exhibit to the Company’s report on Form 8-K, dated November 26, 2007, as filed with the Securities and Exchange Commission on November 29, 2007.

5.		Filed as an exhibit to the Company’s report on Form 8-K, dated January 4, 2008, as filed with the Securities and Exchange Commission on January 10, 2008.

6.		Filed as an exhibit to the Company’s report on Form 8-K, dated February 5, 2008, as filed with the Securities and Exchange Commission on February 8, 2008.

7.		Filed as an exhibit to the Company’s report on Form 8-K, dated December 1, 2000, as filed with the Securities and Exchange Commission on December 15, 2000.

8.		Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended December 31, 2002, dated November 14, 2002, as filed with the Securities and Exchange Commission.

9.		Filed as an exhibit to the Company’s Form 10-SB Registration Statement, as filed with the Securities and Exchange Commission on October 16, 1998.

10.		Filed as an exhibit to the Company’s report on Form 8-K, dated May 11, 2007, as filed with the Securities and Exchange Commission on May 17, 2007.

11.		Filed as an exhibit to the Company’s report on Form 8-K, dated January 3, 2008, as filed with the Securities and Exchange Commission on January 9, 2008.

12.		Filed as an exhibit to the Company’s report on Form 8-K, dated April 3, 2008, as filed with the Securities and Exchange Commission on April 9, 2008.

13.		Filed as an exhibit to the Company’s report on Form 8-K, dated January 17, 2008, as filed with the Securities and Exchange Commission on January 24, 2008.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereto duly authorized.


	CONTANGO OIL & GAS COMPANY
Date: May 12, 2008	By:	/s/ KENNETH R. PEAK
		Kenneth R. Peak
		Chairman, Chief Executive Officer and Chief Financial Officer (Principal Executive and Financial Officer)


Date: May 12, 2008	By:	/s/ LESIA BAUTINA
		Lesia Bautina
		Senior Vice President and Controller (Principal Accounting Officer)

INDEX TO EXHIBITS


Exhibit
Number		Description
	2.1	Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and REX Offshore Corporation, dated as of September 1, 2005. (1)

	2.2	Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and COE Offshore, LLC dated as of September 1, 2005. (1)

	2.3	Purchase and Sale Agreement between Contango STEP, LP and Rosetta Resources Operating LP, dated April 28, 2006. (2)

	2.4	Purchase and Sale Agreement between Contango Operators, Inc. and Rosetta Resources Offshore LLC, dated December 14, 2006. (3)

	2.5	Asset Purchase Agreement by and among Petrohawk Energy Corporation and Contango Operators Inc. (successor-in-interest to Contango Gas Solutions, L.P.), Alta Resources, L.L.C., GPM Energy, LLC, MND Partners, L.P. and TePee Petroleum Company, Inc., dated as of November 26, 2007. (4)

	2.7	Asset Purchase Agreement by and among XTO Energy Inc. and Contango Operators, Inc., Alta Resources, L.L.C., GPM Energy, LLC, MND Partners, L.P. and TePee Petroleum Company, Inc., dated as of January 4, 2008. (5)

	2.8	Partnership Interest Purchase Agreement by and among Turbo LNG LLC, Contango Sundance, Inc. and Osaka Gas Co., Ltd., as Guarantor, dated January 7, 2008. (6)

	3.1	Certificate of Incorporation of Contango Oil & Gas Company. (7)

	3.2	Bylaws of Contango Oil & Gas Company. (7)

	3.3	Agreement of Plan of Merger of Contango Oil & Gas Company, a Delaware corporation, and Contango Oil & Gas Company, a Nevada corporation. (7)

	3.4	Amendment to the Certificate of Incorporation of Contango Oil & Gas Company. (8)

	4.1	Facsimile of common stock certificate of Contango Oil & Gas Company. (9)

	4.2	Certificate of Designations, Preferences and Relative Rights and Limitations for Series E Perpetual Cumulative Convertible Preferred Stock of Contango Oil & Gas Company. (10)


Exhibit
Number		Description
	4.3	Securities Purchase Agreement, dated as of May 11, 2007, among Contango Oil & Gas Company and the Purchasers named therein, relating to the Series E Perpetual Cumulative Convertible Preferred Stock. (10)

	10.1	Assignment of Operating Rights Interest between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.2	Partial Assignment of Oil and Gas Leases between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.3	Assignment of Operating Rights Interest between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.4	Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.5	Partial Assignment of Oil and Gas Leases between Olympic Energy Partners, LLC and Contango Operators, Inc. dated as of January 3, 2008. (11)

	10.6	Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.7	Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.8	Partial Assignment of Oil and Gas Leases between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.9	Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008. (11)

	10.10	Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008. (12)

	10.11	Partial Assignment of Oil and Gas Leases between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008. (12)

	10.12	Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008. (12)

	10.13	Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of April 3, 2008. (12)

	10.14	Partial Assignment of Oil and Gas Leases between Olympic Energy Partners, LLC and Contango Operators, Inc. dated as of April 3, 2008. (12)

	10.15	Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of April 3, 2008. (12)

	10.16	Amended and Restated Limited Liability Company Agreement of Republic Exploration LLC, dated April 1, 2008. (12)

	10.17	Third Amendment to Term Loan Agreement, dated as of January 17, 2008, between Contango Oil & Gas Company, as Borrower, and Centaurus Capital LLC, as Lender. (13)

	10.18	Fourth Amendment to Term Loan Agreement, dated as of February 13, 2008, between Contango Oil & Gas Company, as Borrower, and Centaurus Capital LLC, as Lender. †

	23.2	Consent of William M. Cobb & Associates, Inc. †

	31.1	Certification required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934. †

	32.1	Certification pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. †


†		Filed herewith.

1.		Filed as an exhibit to the Company’s report on Form 8-K, dated September 2, 2005, as filed with the Securities and Exchange Commission on September 8, 2005.

2.		Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended March 31, 2006, dated May 15, 2006, as filed with the Securities and Exchange Commission.

3.		Filed as an exhibit to the Company’s report on Form 8-K, dated December 14, 2006, as filed with the Securities and Exchange Commission on December 20, 2006.


4.		Filed as an exhibit to the Company’s report on Form 8-K, dated November 26, 2007, as filed with the Securities and Exchange Commission on November 29, 2007.

5.		Filed as an exhibit to the Company’s report on Form 8-K, dated January 4, 2008, as filed with the Securities and Exchange Commission on January 10, 2008.

6.		Filed as an exhibit to the Company’s report on Form 8-K, dated February 5, 2008, as filed with the Securities and Exchange Commission on February 8, 2008.

7.		Filed as an exhibit to the Company’s report on Form 8-K, dated December 1, 2000, as filed with the Securities and Exchange Commission on December 15, 2000.

8.		Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended December 31, 2002, dated November 14, 2002, as filed with the Securities and Exchange Commission.

9.		Filed as an exhibit to the Company’s Form 10-SB Registration Statement, as filed with the Securities and Exchange Commission on October 16, 1998.

10.		Filed as an exhibit to the Company’s report on Form 8-K, dated May 11, 2007, as filed with the Securities and Exchange Commission on May 17, 2007.

11.		Filed as an exhibit to the Company’s report on Form 8-K, dated January 3, 2008, as filed with the Securities and Exchange Commission on January 9, 2008.

12.		Filed as an exhibit to the Company’s report on Form 8-K, dated April 3, 2008, as filed with the Securities and Exchange Commission on April 9, 2008.

13.		Filed as an exhibit to the Company’s report on Form 8-K, dated January 17, 2008, as filed with the Securities and Exchange Commission on January 24, 2008.