Edgar Filing: CONTANGO OIL & GAS CO

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2007

¨	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 x No ¨

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

Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨

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

The total number of shares of common stock, par value $0.04 per share, outstanding as of October 31, 2007 was 16,027,138.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2007

TABLE OF CONTENTS


		Page
	PART I – FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets as of September 30, 2007 and June 30, 2007	3
	Consolidated Statements of Operations for the three months ended September 30, 2007 and 2006	5
	Consolidated Statements of Cash Flows for the three months ended September 30, 2007 and 2006	6
	Consolidated Statement of Shareholders’ Equity for the three months ended September 30, 2007	7
	Notes to the Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	42
Item 4.	Controls and Procedures	42

	PART II – OTHER INFORMATION

Item 1A.	Risk Factors	42
Item 6.	Exhibits	43

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


	September 30, 2007			June 30, 2007
	(Unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	8,904,550		$	6,177,618
Short-term investments		—			2,200,576
Inventory tubulars		334,797			334,797
Accounts receivable:
Trade receivables		9,874,489			7,853,080
Advances to affiliates		5,864,042			5,259,191
Joint interest billings receivable		19,182,533			7,894,505
Other receivables		2,264,785			—
Prepaid capital costs		8,162,542			5,539,419
Income tax receivable		—			2,666,884
Other		583,046			255,788

Total current assets		55,170,784			38,181,858

PROPERTY AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties		102,626,294			82,655,848
Unproved properties		22,527,631			22,012,054
Furniture and equipment		244,614			235,512
Accumulated depreciation, depletion and amortization		(6,367,209	)		(3,584,618	)

Total property and equipment, net		119,031,330			101,318,796

OTHER ASSETS:
Cash and other assets held by affiliates		—			1,195,074
Investment in Freeport LNG Project		3,243,585			3,243,585
Investment in Contango Venture Capital Corporation		4,729,909			5,864,558
Deferred income tax asset		663,754			3,377,016
Facility fees and other assets		437,600			754,622

Total other assets		9,074,848			14,434,855

TOTAL ASSETS	$	183,276,962		$	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


	September 30, 2007			June 30, 2007
	(Unaudited)
CURRENT LIABILITIES:
Accounts payable	$	20,162,437		$	14,659,860
Joint interest advances		15,433,177			—
Accrued exploration and development		11,757,127			14,235,062
Advances from affiliates		3,504,429			3,417,103
Debt of affiliates		13,237,141			8,540,091
Other liabilities held by affiliates		520,531			—
Other accrued liabilities		1,177,913			1,417,279

Total current liabilities		65,792,755			42,269,395

LONG-TERM DEBT		20,000,000			20,000,000

ASSET RETIREMENT OBLIGATION		862,344			862,344

SHAREHOLDERS’ EQUITY:
Convertible preferred stock, 6%, Series E, $0.04 par value, 10,000 shares authorized, 6,000 shares issued and outstanding at September 30, 2007 and June 30, 2007, liquidation preference of $30,000,000 at $5,000 per share		240			240
Common stock, $0.04 par value, 50,000,000 shares authorized, 18,596,138 shares issued and 16,021,138 outstanding at September 30, 2007, 18,539,807 shares issued and 15,964,807 outstanding at June 30, 2007		743,844			741,591
Additional paid-in capital		76,698,259			75,849,506
Accumulated other comprehensive income (loss)		(38,724	)		715,659
Treasury stock at cost (2,575,000 shares)		(6,180,000	)		(6,180,000	)
Retained earnings		25,398,244			19,676,774

Total shareholders’ equity		96,621,863			90,803,770

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	183,276,962		$	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 September 30,
	2007			2006
REVENUES:
Natural gas and oil sales	$	14,128,014		$	1,192,306

Total revenues		14,128,014			1,192,306

EXPENSES:
Operating expenses		1,674,645			132,949
Exploration expenses		411,389			401,347
Depreciation, depletion and amortization		2,869,527			212,191
General and administrative expenses		1,342,461			1,103,342

Total expenses		6,298,022			1,849,829

NET INCOME (LOSS) BEFORE OTHER INCOME AND INCOME TAXES		7,829,992			(657,523	)

Interest expense (net of interest capitalized)		(829,860	)		(167,471	)
Interest income		364,314			251,659
Other income		2,122,660			84,391

NET INCOME (LOSS) BEFORE INCOME TAXES		9,487,106			(488,944	)
Benefit (provision) for income taxes		(3,315,636	)		233,088

NET INCOME (LOSS)		6,171,470			(255,856	)
Preferred stock dividends		450,000			150,000

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	5,721,470		$	(405,856	)

NET INCOME (LOSS) PER SHARE:
Basic	$	0.36		$	(0.03	)
Diluted	$	0.35		$	(0.03	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		15,991,762			15,004,548

Diluted		16,419,956			15,004,548

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended September 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	6,171,470		$	(255,856	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		2,869,527			212,191
Exploration expenditures		316,392			531,907
Deferred income taxes		3,119,467			(262,120	)
Tax benefit from exercise/cancellation of stock options		(60,848	)		(29,032	)
Stock-based compensation		396,508			229,160
Changes in operating assets and liabilities:
Increase in accounts receivable and other		(4,251,545	)		(289,673	)
Increase in prepaid insurance		(399,346	)		(188,250	)
Increase in interest receivable		(250,000	)		(20,599	)
Increase in inventory		—			(139,972	)
Increase in accounts payable and advances from joint owners		24,825,056			7,472,889
Decrease in other accrued liabilities		(244,919	)		(398,409	)
Increase in income taxes payable		2,727,732			29,032
Gain on sale of assets and other		(25,940	)		(84,391	)

Net cash provided by operating activities		35,193,554			6,806,877

CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures		(41,075,249	)		(22,281,393	)
Increase in net investment in affiliates		1,715,605			292,031
Sale of short-term investments		2,200,576			9,460,677
Additions to furniture and equipment		(9,102	)		—
Investment in Contango Venture Capital Corporation		—			(600,000	)

Net cash used in investing activities		(37,168,170	)		(13,128,685	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings by affiliates		4,697,050			—
Preferred stock dividends		(450,000	)		(150,000	)
Repurchase/cancellation of stock options and warrants		—			(181,540	)
Tax benefit from exercise/cancellation of stock options		60,848			29,032
Proceeds from exercised options, warrants and others		393,650			—

Net cash provided (used) in financing activities		4,701,548			(302,508	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		2,726,932			(6,624,316	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		6,177,618			10,274,950

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	8,904,550		$	3,650,634

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for taxes	$	—		$	—

Cash paid for interest	$	1,065,694		$	201,645

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 Three Months Ended September 30, 2007
									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

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 months ended September 30, 2007 are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2008.

1. 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.

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.

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 September 30, 2007, the Company had $8,904,550 in cash and cash equivalents, of which $213,165 was invested in highly liquid AAA-rated tax-exempt money market funds.

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 42.7% owned Republic Exploration LLC (“REX”), 50% owned Magnolia Offshore Exploration LLC (“MOE”), and 76.0% owned Contango Offshore Exploration LLC (“COE”) are not controlled by the Company and are proportionately consolidated.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Upon the formation of REX and MOE, Contango was the only owner that contributed cash, and under the terms of the respective limited liability company agreements, was entitled to all of the ventures’ assets and liabilities until the ventures expended all of the Company’s initial cash contribution. The Company therefore consolidated 100% of the ventures’ net assets and results of operations. During the quarter ended December 31, 2002, both REX and MOE completed exploration activities to fully expend the Company’s initial cash contribution, thereby enabling each owner to share in the net assets of the venture based on their stated ownership percentages. Commencing with the quarter ended December 31, 2002, the Company began consolidating 33.3% and 50.0% of the net assets and results of operations of REX and MOE, respectively. The reduction of our ownership in the net assets of REX and MOE resulted in a non-cash exploration expense of approximately $4.2 million and $0.2 million, respectively. The other owners of REX contributed seismic data and related geological and geophysical services, while the other owner of MOE contributed geological and geophysical services in exchange for its 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.

Contango’s 10% limited partnership interest in Freeport LNG Development, L.P. (“Freeport LNG”) is accounted for at cost. As a 10% limited partner, the Company has no ability to direct or control the operations or management of the general partner.

Contango’s 32% ownership in Contango Capital Partnership Management, LLC (“CCPM”), Contango’s 25% limited partnership interest in Contango Capital Partners, L.P. (“CCPLP”) and Contango’s 33% ownership of Moblize Inc. (“Moblize”) are accounted for using the equity method. Under the equity method, only Contango’s investment in and amounts due to and from the equity investee are included in the consolidated balance sheet. CCPLP formed the Contango Capital Partners Fund, LP (the “Fund”) in January 2005. The Fund owns equity interests in a portfolio of alternative energy companies. The Fund marks these equity interests to market according to fair market values on a quarterly basis.

Contango’s investment in Gridpoint, Inc. (“Gridpoint”) is accounted for using the cost method. Under the cost method, Contango records an investment in the stock of an investee at cost, and recognizes dividends received as income. Dividends received in excess of earnings subsequent to the date of investment are considered a return of investment and are recorded as reductions of cost of the investment.

Contango’s investment in Trulite, Inc. (“Trulite”) is accounted for in accordance with Statement of Financial Accounting Standard (“SFAS”) No. 115 (“SFAS 115”), “Accounting for Certain Investments in Debt and Equity Securities”. SFAS 115 applies to preferred stock and common stock, if ownership is less than 20%, or if ownership exceeds 20% but effective control (significant influence) is lacking. It is not applicable to investments under the equity method. Due to the nature and objective of our investment in Trulite, these securities are classified as available-for-sale securities under SFAS 115. Any unrealized gains or losses while marking these securities to market are reflected as a component of other comprehensive income at September 30, 2007.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Recent Accounting Pronouncements. In February 2007, the Financial Accounting Standards Board (“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 or 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 or 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. No options were granted for the three months ended September 30, 2007. The fair value of each option is estimated as of the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants during the quarter ended September 30, 2006: (i) risk-free interest rate of 4.56 percent; (ii) expected life of five years; (iii) expected volatility of 40 percent and (iv) expected dividend yield of zero percent.

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. For the three months ended September 30, 2007, the Company granted 331 shares of restricted stock to a new member of the Board. For the three months ended September 30, 2007 and 2006, the Company recorded stock-based compensation charges of $396,508 and $229,160 to general and administrative expense, respectively, for restricted stock and option awards granted in prior fiscal years.

2. Natural Gas and Oil Exploration 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.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

3. Credit Risk

The majority of the Company’s revenues for the three months ended September 30, 2007 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.

4. 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 September 30, 2007
	Income (Loss)			Weighted Average Shares		Per Share
Net income, including preferred dividends	$	5,721,470		15,991,762		$	0.36

Basic Earnings per Share:
Net income attributable to common stock	$	5,721,470		15,991,762		$	0.36

Effect of Potential Dilutive Securities:
Stock options		—		428,194
Series E preferred stock		(a	)	(a	)

Net income, including preferred dividends	$	5,721,470		16,419,956		$	0.35

Diluted Earnings per Share:
Net income attributable to common stock	$	5,721,470		16,419,956		$	0.35

Anti-dilutive Securities:
Series E preferred stock	$	450,000		789,468		$	0.57

(a)	Anti-dilutive.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. Net Income (Loss) Per Common Share - continued


	Three Months Ended September 30, 2006
	Income (Loss)			Weighted Average Shares		Per Share
Net loss, including preferred dividends	$	(405,856	)	15,004,548		$	(0.03	)

Basic Earnings per Share:
Net loss attributable to common stock	$	(405,856	)	15,004,548		$	(0.03	)

Effect of Potential Dilutive Securities:
Stock options		—		(a	)
Series D preferred stock		(a	)	(a	)

Net loss, including preferred dividends	$	(405,856	)	15,004,548		$	(0.03	)

Diluted Earnings per Share:
Net loss attributable to common stock	$	(405,856	)	15,004,548		$	(0.03	)

Anti-dilutive Securities:
Shares assumed not issued from options to purchase common shares as income from continuing operations was in a loss position for the period	$	—		925,875		$	7.93
Series D preferred stock	$	150,000		833,330		$	0.18

(a)	Anti-dilutive.

5. 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 January 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 January 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 and 2006 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed.

6. Contango Venture Capital Corporation

As of September 30, 2007, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, held a direct investment in Trulite, Inc. Trulite is a publicly traded company. We account for this investment in accordance with SFAS No. 115 (“SFAS 115”) “Accounting for Certain Investments in Debt and Equity Securities”.

As of September 30, 2007, CVCC had invested $0.9 million in Trulite in exchange for 2,001,014 shares of Trulite common stock, which represents an approximate 17% ownership interest. Trulite develops lightweight hydrogen generators for fuel cell systems, and recently began trading publicly on over the counter bulletin boards under the stock symbol “TRUL.OB”. Accordingly, we mark-to-market our investment in Trulite based on public

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

pricing. At September 30, 2007, our investment in Trulite had a mark-to-market value of approximately $0.8 million based on a closing stock price of $.42 per share. Trulite is a startup company with very little trading volume and thus the purchase or sale of relatively small common stock positions may result in disproportionately large increases or decreases in the price of its common stock. An unrealized loss of approximately $0.8 million, net of tax, has been reflected as a component of other comprehensive income at September 30, 2007.

7. Long-Term Debt

The Company has a $30.0 million secured term loan agreement with a private investment firm (the “Term Loan Agreement”). The Term Loan Agreement is secured with substantially all the assets of the Company, except for the stock of Contango Sundance, Inc. (“Sundance”), our wholly-owned subsidiary. As of September 30, 2007, the Company had no amounts borrowed under the Term Loan Agreement. Borrowings under the Term Loan Agreement bear interest at 30 day LIBOR plus 5.0%. Accrued interest is due monthly. The principal is due December 31, 2008, but we may prepay at any time with no prepayment penalty. An arrangement fee of 1%, or $300,000, was paid in connection with the term loan. Additionally, we pay a non-use fee in the amount of 1.50% per annum multiplied by such non-funded amount.

The Company has $20.0 million outstanding under a three-year $20.0 million secured term loan facility with The Royal Bank of Scotland plc (the “RBS Facility”). The RBS Facility is secured with the stock of Sundance. Sundance owns a 10% limited partnership interest in Freeport LNG, which owns the Freeport LNG facility. Borrowings under the RBS Facility bear interest, at the Company’s option, at either (i) 30 day LIBOR, (ii) 60 day LIBOR, (iii) 90 day LIBOR or (iv) 6 month LIBOR, all plus 6.5%. Interest is due at the end of the LIBOR period chosen. The principal is due April 27, 2009, but we may prepay after April 27, 2008 with no prepayment penalty.

Both the Term Loan Agreement and the RBS Facility require a minimum level of working capital and contain 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 and RBS Facility could result in a default and acceleration of all indebtedness under such credit facilities. As of September 30, 2007, the Company was in compliance with its financial covenants, ratios and other provisions of the Term Loan Agreement and RBS Facility.

8. Related Party Transactions

On October 26, 2006, REX executed a Demand Promissory Note (the “REX Demand Note”) with a private investment firm which is non-recourse to Contango. Under the terms of the REX Demand Note, REX can 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 are payable in full on the earlier of October 26, 2008 or upon demand. As of September 30, 2007, REX had borrowed $31.0 million under the REX Demand Note. The Company is not a party to or guarantor of the REX Demand Note, but as a result of our proportionate consolidation of REX, approximately $13.2 million is reflected as a current liability on our balance sheet as of September 30, 2007. The REX Demand Note is secured by substantially all the assets of REX including the production attributable to REX from our Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) exploration discoveries in the Gulf of Mexico. For the three months ended September 30, 2007, the Company’s proportionate share of such interest expense was approximately $349,000.

On August 20, 2007, the Company executed a fifth promissory note with Trulite to loan Trulite $250,000. When combined with the first four promissory notes, this brings the total amount loaned to Trulite to $1,255,000. This fifth promissory note bears interest at a per annum rate of 12.25% until February 14, 2008, at which point the per annum rate will change to prime rate plus four percentage points until May 16, 2008, which is when the promissory note plus all accrued and unpaid interest is due. This note is not subject to the subscription agreement between the Company and Trulite pursuant to which the parties agreed to convert the aggregate principal balance of

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the first three promissory notes and all accrued but unpaid interest thereon into shares of Trulite common stock. For the three months ended September 30, 2007, the Company earned approximately $36,000 in interest income from all five Trulite promissory notes.

9. Other Income

Other Income for the three months ended September 30, 2007 totaled approximately $2.1 million. Of this amount, approximately $2.2 million relates to a payment from a stockholder related to a short swing profit liability. In September 2007, one of our stockholders determined that it had inadvertently engaged in trades which resulted in automatic short swing profit liability to the Company pursuant to Section 16(b) of the Securities Exchange Act of 1934. After becoming aware of the situation, the stockholder promptly made a payment of approximately $2.2 million to the Company to settle the entire short swing profit liability owed as a consequence of these trades.

10. Subsequent Events

On October 9, 2007, REX borrowed an additional $6.0 million under the REX Demand Note, and on October 31, 2007, REX borrowed an additional $4.0 million under the REX Demand Note, bringing the total amount outstanding under the REX Demand Note to $41.0 million. The interest rate on the borrowings is at a per annum rate of LIBOR plus six percent. The note is non-recourse to Contango. Contango’s share of such obligation and interest expense will be reflected in future financial statements as a result of our proportionate consolidation of REX.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

•

Development, construction and financing of our liquefied natural gas (“LNG”) receiving terminal

•

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

•

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

•

Ability of LNG to become a competitive energy supply in the United States

•

Ability to fund our LNG project, cost overruns and third party performance

•

Successful commercialization of alternative energy technologies

•

Drilling and operating costs, production rates and ultimate reserve recoveries in our Arkansas Fayetteville Shale play

•

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 Republic Exploration, LLC (“REX”), our partially-owned subsidiary, to fund its 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 and in the Arkansas Fayetteville Shale. Contango Operators, Inc. (“COI”), our wholly-owned subsidiary, acts as operator on certain offshore prospects. The Company also owns a 10% interest in a limited partnership formed to develop an LNG receiving terminal in Freeport, Texas, and holds investments in companies focused on commercializing environmentally preferred energy technologies.

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 partners. We depend totally upon our alliance partners for prospect generation expertise. Our alliance partners, Juneau Exploration, L.P. (“JEX”) and Alta Resources, LLC (“Alta”) are experienced and have successful track records in exploration.

Using our limited capital availability to increase our reward/risk potential on selective prospects. We have concentrated our risk investment capital in two prospect areas; our onshore Arkansas Fayetteville Shale play and 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 our 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.

Arkansas Fayetteville Shale. We have made a major commitment to our Arkansas Fayetteville Shale program and this commitment is expected to continue to grow as we participate in the drilling of hundreds of gross exploration/development wells over the next five to ten years.

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, LNG and alternative energy investment activities. Since its inception, the Company has sold over $87.0 million worth of natural gas and oil properties, 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.

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 partners share 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 24% of our common stock.

Exploration Alliances with JEX and Alta

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, COE and MOE (see “Offshore Gulf of Mexico Exploration Joint Ventures” below).

Alliance with Alta. Alta is a private company formed for the purpose of assembling domestic, onshore natural gas and oil prospects. Our arrangement with Alta generally provides for us to pay our share of seismic and lease costs, with Alta generally receiving a negotiated overriding royalty interest and a carried or back-in working interest.

Onshore Exploration and Properties

Alta Activities

Arkansas Fayetteville Shale

In March 2005, Contango, Alta and another private company entered into an agreement to acquire natural gas, oil, and mineral leases in the Arkansas Fayetteville Shale play area located in Pope, Van Buren, Conway, Faulkner, Cleburne, and White Counties, Arkansas. As of October 31, 2007, we and our partners have acquired or received commitments on approximately 44,300 net mineral acres at a cost of approximately $13.7 million. Our 70% share of the acquisition costs is approximately $9.6 million.

The Arkansas Oil & Gas Commission has approved 16 separate 640-acre drilling units in Conway, Van Buren, Faulkner and Cleburne Counties, Arkansas that we estimate will allow Alta to potentially drill and operate up to approximately 144 horizontal wells. Horizontal wells are estimated to cost between $3.5 to $2.5 million each, depending on depth and lateral length. Alta intends to continue to seek approval from the Arkansas Oil & Gas Commission for additional 640-acre units.

Of the wells drilled by Tepee Petroleum as contract operator, the Alta-Thines #1-30H is currently producing at 0.5 million cubic feet per day (“Mmcf/d”), the Alta-Ledbetter #1-33H is currently producing at 0.6 Mmcf/d, the Alta-Clark #1-26H is currently producing at 0.6 Mmcf/d and the Alta-Wooten #1-34H is currently producing at 0.7 Mmcf/d. The Alta-Briggler #1-31H is shut in awaiting pipeline hookup. The Company has invested approximately $12.1 million to drill and complete these five wells.

Of the wells drilled by Alta Operating Company, the Alta-Huff #1-29H is currently producing at 1.2 Mmcf/d, the Alta- Jones #1-29H is currently producing at 2.6 Mmcf/d, the Alta-Chwalinski #2-29H is currently producing at 1.4 Mmcf/d, and the Alta-Chwalinski #3-29H is currently producing at 1.2 Mmcf/d. Alta also operates two wells drilled by a third party operator on Alta’s behalf, the Alta-Chwalinski #1-29H which is currently producing at 0.9 Mmcf/d and the Alta-Koone #1-4H which is currently producing at 0.3 Mmcf/d. In October 2007, the Deltic #1-8H and Alta-Deltic #2-8H wells, the first Alta operated wells drilled in our Eastern core area, were simultaneously fracture stimulated and are currently flowing to sales at a combined rate of 4.6 Mmcf/d. The Company has invested approximately $9.6 million to drill and complete these eight wells.

Additionally, Alta spud the Alta-Deltic #1-18H in September 2007 and the Alta-Black #1-4H in October 2007. The 8/8ths cost for drilling and completing these two wells is estimated to be $6.4 million (approximately $2.7 million net to Contango). Both wells are drilled, cased and awaiting completion. Alta has extended its rig contract by five wells in our Eastern core area and plans to continue to drill for the foreseeable future. Contango’s net average working interest and net revenue interest in the 15 Alta-operated wells described above, prior to project payout, are approximately 50% and 40%, respectively. As of November 5, 2007, these 12 Alta-operated wells were producing at a combined rate of approximately 5.8 Mmcf/d, net to Contango.

In addition, we have been integrated by a third party independent oil and gas exploration company into 152 wells as of October 31, 2007 (the “Integrated Wells”). Of these 152 Integrated Wells, 89 are producing. The 8/8ths production rate for 85 of these 89 producing Integrated Wells was 65.9 Mmcf/d as of October 31, 2007 (approximately 3.3 Mmcf/d, net to Contango). Production data for the remaining four producing Integrated Wells is not available. The remaining 63 Integrated Wells are either currently being drilled or are expected to be drilled over the next several months. The 8/8ths cost for drilling and completing these 63 wells is estimated to be approximately $168.6 million (approximately $7.3 million net to Contango). Of this $7.3 million, we have already invested approximately $0.4 million as of September 30, 2007. Contango’s net average working interest and net revenue interest in these 152 wells are approximately 6% and 5%, respectively.

Texas, Alabama and Louisiana

Outside of Arkansas, the Alta-Ellis #1 is currently producing at a rate of 0.4 million cubic feet equivalent per day (“Mmcfe/d”) and the Temple Inland #1 is currently producing at a rate of approximately 0.9 MMcfe/d.

Offshore Gulf of Mexico Exploration Joint Ventures

Contango directly and through affiliated companies conducts exploration activities in the Gulf of Mexico. As of October 31, 2007, Contango and its affiliates have interests in 71 offshore leases. See “Offshore Properties” below for additional information on our offshore properties.

Republic Exploration LLC. REX was recently awarded Eugene Island 11, which REX bid on at the Central Gulf of Mexico Lease Sale No. 205. The lease has been awarded to REX, but not yet paid for or executed.

On August 22, 2007, REX was the apparent high bidder on two lease blocks at the Western Gulf of Mexico Lease Sale No. 204. An apparent high bid (“AHB”) gives the bidding party priority in award of offered tracts, 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. REX bid approximately $1.75 million on High Island 263, and approximately $1.1 million on High Island A38.

In June 2007, REX was awarded State Lease No. 19396 at the State of Louisiana Mineral Lease Sale for an aggregate purchase price of approximately $0.3 million. State Lease No. 19396, together with our other State of Louisiana prospects, are commonly referred to as the “Mary Rose” prospect.

In February 2007, REX was awarded State Leases No. 19261 and 19266 at the State of Louisiana Mineral Lease Sale for an aggregate purchase price of approximately $4.6 million ($1.8 million net to Contango).

Contango Offshore Exploration LLC. Grand Isle 72 (“Liberty”), a COE prospect, began producing in March 2007 and as of October 31, 2007 was producing at a rate of approximately 0.6 Mmcfe/d. As of September 30, 2007, COE had invested approximately $5.4 million (approximately $4.1 million net to Contango) to drill and complete Grand Isle 72, including pipeline and production facility costs.

Magnolia Offshore Exploration LLC. As of September 30, 2007, Contango had approximately $1.0 million invested in MOE. JEX is the only other member of MOE and acts as the managing member, deciding which prospects MOE may acquire, develop, and exploit. MOE’s license rights to 3-D seismic data have been assigned to COE. All leases are subject to a 3.3% ORRI in favor of the JEX prospect generation team. See “Offshore Properties” below for additional information on MOE’s offshore properties.

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 has non-operating working interests in three 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 October 31, 2007, Ship Shoal 358, in which the Company has a 5.8% net revenue interest, was producing at a rate of approximately 4.9 Mmcfe/d and West Delta 36 was producing at a rate of approximately 11.6 Mmcfe/d. REX has a 3.67% ORRI before payout in West Delta 36, and at its option, may elect either a 5.0% ORRI or 25% working interest (“WI”) after payout. Eugene Island 113-B, in which the Company has a 3.1% net revenue interest, is not currently producing while compression is being installed.

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 will operate and acquire 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. In October 2007, the Company announced a discovery at its Mary Rose #1 well, located on State of Louisiana Lease No. 18640, and in November 2007 we announced that our Dutch #3 well had commenced production.

The Mary Rose #1 well was production tested in November 2007 at a rate of approximately 25.0 Mmcfe/d. The well is expected to begin producing in the spring of 2008 to a platform to be set at Eugene Island 11 that is currently under construction. Platform and pipeline installation are expected to begin in February 2008. 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 the Mary Rose #1 well and from an expected additional three to five wells. The Company expects it will take between seven to nine wells to fully develop its Dutch and Mary Rose discoveries. As of September 30, 2007, the Company had invested approximately $2.9 million to drill and complete the Mary Rose #1, and has budgeted to invest an additional $0.9 million to bring the Mary Rose #1 well to production. Additionally, the Company has budgeted to invest approximately $7.8 million for the remainder of fiscal year 2008 in pipeline and platform costs. COI has a 15.7% working interest and an 11.3% net revenue interest in Mary Rose #1.

We are currently on location building the pad for the Mary Rose #2 well, which we expect to begin drilling in December 2007. We believe both the Mary Rose #1 and #2 wells will be ready to flow into our Eugene Island 11 platform facility upon its completion.

As of October 31, 2007, our Dutch #1 and #2 wells were flowing at a combined 8/8ths production rate of approximately 72.2 Mmcfe/d. As of September 30, 2007, the Company had invested approximately $12.6 million to

drill and complete Dutch #1 and #2, including pipeline and production facility costs. During June 2007, one of the farmors of the Eugene Island 10 block backed in for a 12.5% working interest. Therefore, COI now has a 16.04% WI and REX has a 56.88% WI in each of the Dutch wells. For sales of natural gas, the net revenue interests to COI and REX are approximately 14.7% and 52.1%, respectively, with MMS deep gas royalty relief on the first 15 Bcf of gas produced from the entire field. Once the royalty relief has expired for natural gas, and for all sales of oil and condensate, COI and REX have a net revenue interest of 12.07% and 42.79%, respectively. The lease was farmed in on a produce-to-earn basis. The lease has now been assigned, and REX has earned the lease.

The Company’s Dutch #3 well began production in November 2007 and as of November 6, 2007 was flowing at an 8/8ths production rate of approximately 23.0 Mmcfe/d (approximately 7.0 Mmcfe/d net to Contango). Production from our Dutch #1 and Dutch #2 wells was reduced to allow for Dutch #3 to come onstream. The three Dutch wells are producing at a combined 75.0 Mmcfe/d (approximately 23.0 Mmcfe/d net to Contango). Our three Dutch wells flow to a platform at Eugene Island 24, which is owned and operated by a third party. This platform is undergoing facility upgrades that are anticipated to permit us to increase the 8/8ths platform production capacity available to Contango and its partners for the Dutch #1, #2 and #3 wells to 100 Mmcf/d and 2,000 Bbls/d, beginning in December 2007.

As of September 30, 2007, the Company had invested approximately $4.0 million to drill and complete this well, including pipeline and production facility costs. We estimate an additional $3.9 million will be required for the production and pipeline facilities. COI has a 16.04% WI and REX has a 56.88% WI in Dutch #3. For sales of natural gas, the net revenue interests to COI and REX are approximately 14.7% and 52.1%, respectively, with MMS deep gas royalty relief on the first 15 Bcf of gas produced from the entire field. Once the royalty relief has expired for natural gas, and for all sales of oil and condensate, COI and REX have a net revenue interest of 12.07% and 42.79%, respectively. Once the second farmor backs in after project payout, COI and REX’s working interests will be reduced to 13.75% and 48.75%, respectively.

The Company’s independent third party engineer estimates the Dutch and Mary Rose discoveries to have total proved reserves of 380 billion cubic feet equivalent (“Bcfe”) (108 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 November 6, 2007:


Area/Block	WI	NRI	Status
Contango Operators, Inc.:
Eugene Island 113B	0.0%	1.7%	Awaiting installation of compression
Eugene Island 10 #1	16.0%	14.7%	Producing
Eugene Island 10 #2	16.0%	14.7%	Producing
Eugene Island 10 #3	16.0%	14.7%	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%	Awaiting installation of compression
West Delta 36	(1)	(1)	Producing
Eugene Island 10 #1	56.9%	52.1%	Producing
Eugene Island 10 #2	56.9%	52.1%	Producing
Eugene Island 10 #3	56.9%	52.1%	Producing

(1)	REX has a 3.67% ORRI before payout and, at its option, may elect either a 5.0% ORRI or 25% WI after payout.

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 October 31, 2007:


Area/Block	WI	NRI	Status
Republic Exploration LLC:
Vermilion 154	(2)	(2)	Drilling expected by summer 2008
Vermilion 73	(3)	(3)	Dry hole
South Marsh Island 247	(4)	(4)	Dry hole

Contango Offshore Exploration LLC:
East Breaks 369	—	—	Dry hole
East Breaks 370	(5)	(5)	No drilling date has been determined yet
Vermilion 154	(2)	(2)	Drilling expected by summer 2008

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

(3)	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.

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

(5)	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 October 31, 2007:


Area/Block	WI	Lease Date
Contango Operators, Inc.:
West Cameron 174	10.0%	Jul-03
Grand Isle 63	25.0%	May-04
Grand Isle 73	25.0%	May-04
West Delta 43	35.0%	May-04
S-L 18640 (LA)	15.7%	Jul-05
S-L 18860 (LA)	15.7%	Jan-06
Ship Shoal 14	37.5%	May-06
Ship Shoal 25	37.5%	May-06
South Marsh Island 57	37.5%	May-06
South Marsh Island 59	37.5%	May-06
South Marsh Island 75	37.5%	May-06
South Marsh Island 282	37.5%	May-06
Grand Isle 70	3.65%	Jun-06
West Delta 77	25.0%	Jun-06
Vermilion 194	37.5%	Jul-06
Eugene Island 10	16.0%	Nov-06
S-L 19261 (LA)	15.7%	Feb-07
S-L 19266 (LA)	15.7%	Feb-07
S-L 19396 (LA)	15.7%	Jun-07

Area/Block	WI	Lease Date
Republic Exploration LLC:
West Cameron 174	90.0%	Jul-03
High Island 113	100.0%	Oct-03
South Timbalier 191	50.0%	May-04
Vermilion 36	100.0%	May-04
Vermilion 109	100.0%	May-04
Vermilion 134	100.0%	May-04
West Cameron 179	100.0%	May-04
West Cameron 185	100.0%	May-04
West Cameron 200	100.0%	May-04
West Delta 18	100.0%	May-04
West Delta 33	100.0%	May-04
West Delta 34	100.0%	May-04
West Delta 43	30.0%	May-04
Ship Shoal 220	50.0%	Jun-04
South Timbalier 240	50.0%	Jun-04
West Cameron 133	100.0%	Jun-04
West Cameron 80	100.0%	Jun-04
West Cameron 167	100.0%	Jun-04
Eugene Island 76	0%	Jul-04
Vermilion 130	100.0%	Jul-04
West Cameron 107	100.0%	May-05
Eugene Island 168	50.0%	Jun-05
S-L 18640 (LA)	55.7%	Jul-05
S-L 18860 (LA)	55.7%	Jan-06
High Island A243	75.0%	Jan-06
South Marsh Island 57	50.0%	May-06
South Marsh Island 59	50.0%	May-06
South Marsh Island 75	50.0%	May-06
South Marsh Island 282	50.0%	May-06
Ship Shoal 14	50.0%	May-06
Ship Shoal 25	50.0%	May-06
West Delta 77	50.0%	Jun-06


Vermilion 194	50.0%	Jul-06
High Island A196	100.0%	Oct-06
High Island A197	100.0%	Oct-06
High Island A198	100.0%	Oct-06
Eugene Island 10	56.9%	Nov-06
S-L 19261 (LA)	55.7%	Feb-07
S-L 19266 (LA)	55.7%	Feb-07
S-L 19396 (LA)	55.7%	Jun-07

Area/Block	WI	Lease Date
Contango Offshore Exploration LLC:
Ship Shoal 358	10.0%	Jun-98
Viosca Knoll 167	100.0%	May-03
Vermilion 231	100.0%	May-03
Viosca Knoll 161	33.3%	Jul-03
Eugene Island 209	100.0%	Jul-03
High Island A16	100.0%	Dec-03
East Breaks 283	100.0%	Dec-03
South Timbalier 191	50.0%	May-04
Grand Isle 63	50.0%	May-04
Grand Isle 72	50.0%	May-04
Grand Isle 73	50.0%	May-04
Ship Shoal 220	50.0%	Jun-04
South Timbalier 240	50.0%	Jun-04
Viosca Knoll 118	33.3%	Jun-04
Viosca Knoll 475	100.0%	May-05
Eugene Island 168	50.0%	Jun-05
East Breaks 366	100.0%	Nov-05
East Breaks 410	100.0%	Nov-05
East Breaks 167	75.0%	Dec-05
High Island A311	75.0%	Dec-05
East Breaks 166	75.0%	Jan-06
High Island A342	75.0%	Jan-06
Ship Shoal 263	75.0%	Jun-06
Grand Isle 70	52.6%	Jun-06
Viosca Knoll 119	50.0%	Jun-06
Viosca Knoll 383	100.0%	Jun-06



Area/Block	WI	Lease Date
Magnolia Offshore Exploration LLC:
Viosca Knoll 161	16.7%	Jul-03
Viosca Knoll 118	16.7%	Jun-04
Viosca Knoll 211	100.0%	Jul-04

Freeport LNG Development, L.P.

As of September 30, 2007, the Company has invested $3.2 million and owns a 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. Startup is expected to occur in the first quarter of calendar year 2008.

Although we anticipate that we may, from time-to-time, be required to provide funds to the Freeport LNG project, and intend to provide our pro rata 10% of any required equity participation, we believe the project will continue through Phase I construction and Phase II pre-development with no further significant funds likely being required from Contango.

Contango Venture Capital Corporation

As of September 30, 2007, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, held a direct investment in three alternative energy portfolio companies – Gridpoint, Inc., Moblize Inc. and Trulite, Inc. Our investment in Gridpoint is less than 20% and we account for this investment under the cost method. Our investment in Moblize rose above 20% during the three months ended September 30, 2006 when the Company exercised its right pursuant to two warrants, to purchase additional shares of the company. We account for this investment under the equity method. Trulite is a publicly traded company. We account for this investment in accordance with SFAS No. 115 (“SFAS 115”) “Accounting for Certain Investments in Debt and Equity Securities”.

Gridpoint, Inc. As of September 30, 2007, CVCC had invested approximately $1.0 million in Gridpoint in exchange for 333,333 shares of Gridpoint preferred stock, which represents an approximate 1.8% ownership interest. Gridpoint’s intelligent energy management products ensure clean, reliable power, increase energy efficiency, and integrate renewable energy. With Gridpoint, home and business owners can automatically protect themselves from power outages, manage their energy online and reduce their carbon footprint.

Moblize Inc. As of September 30, 2007, CVCC had invested $1.2 million in Moblize in exchange for 648,648 shares of Moblize convertible preferred stock, which represents an approximate 33% ownership interest. Moblize develops real time diagnostics and field optimization solutions for the oil and gas and other industries using open-standards based technologies. Moblize has deployed its technology on our Grand Isle 72 well which allows COI to remotely monitor, control and record, in real time, daily production volumes. Moblize is continuing to deploy its technology on oil fields near Houston belonging to Chevron U.S.A. Inc. and on other COI operated wells.

Trulite, Inc. As of September 30, 2007, CVCC had invested $0.9 million in Trulite in exchange for 2,001,014 shares of Trulite common stock, which represents an approximate 17% ownership interest. Trulite develops lightweight hydrogen generators for fuel cell systems, and recently began trading publicly on over the counter bulletin boards under the stock symbol “TRUL.OB”. As a result, we mark-to-market our investment in Trulite based on public pricing. At September 30, 2007, our investment in Trulite had a mark-to-market value of approximately $0.8 million based on a closing stock price of $0.42 per share. Trulite is a startup company with very little trading volume and thus the purchase or sale of relatively small common stock positions may result in disproportionately large increases or decreases in the price of its common stock. An unrealized loss of approximately $0.8 million, net of tax, has been reflected as a component of other comprehensive income at September 30, 2007.

As of September 30, 2007, CVCC owned 25% of Contango Capital Partners Fund, L.P. (the “Fund”). The Fund currently holds a direct investment in two alternative energy companies – Protonex Technology Corporation (“Protonex”) and Jadoo Power Systems (“Jadoo”). We account for our investment in the Fund under the equity method. The Fund, however, accounts for its investment in Protonex in accordance with SFAS 115, and accounts for its investment in Jadoo at fair value in accordance with the AICPA Audit and Accounting Guide, “Investment Companies”.

Protonex Technology Corporation. As of September 30, 2007, the Fund had invested $1.5 million in Protonex in exchange for 2,400,000 shares of Protonex stock, which represents an approximate 7% ownership interest. Protonex provides long-duration portable and remote power sources with a focus on providing solutions to the U.S. military and supplies complete power solutions and application engineering services to original equipment manufacturer’s customers. Protonex trades its common shares on the AIM market of the London Stock Exchange under the stock symbol “PTX.L”. As a result, the Fund marks-to-market its investment in Protonex based on public pricing. At September 30, 2007, the Fund’s investment in Protonex had a mark-to-market value of approximately $4.4 million.

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 September 30, 2007 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 months ended September 30, 2007 and 2006.


	Three Months Ended September 30,
	2007		2006		Change
			($000)
Revenues:
Natural gas, oil and NGL sales	$	14,128	$	1,192	1085	%

Total revenues	$	14,128	$	1,192	1085	%

Production:
Natural gas (million cubic feet)		2,065		144	1334	%
Oil, condensate and NGLs (thousand barrels)		38		4	850	%
Total (million cubic feet equivalent)		2,293		168	1265	%

Natural gas (million cubic feet per day)		22.4		1.6	1303	%
Oil, condensate and NGLs (thousand barrels per day)		0.4		0.1	313	%
Total (million cubic feet equivalent per day)		24.8		2.2	1027	%

Average Sales Price:
Natural gas (per thousand cubic feet)	$	5.83	$	6.25	-7	%
Oil, condensate and NGLs (per barrel)	$	54.99	$	70.21	-22	%

Operating expenses	$	1,675	$	133	1159	%
Exploration expenses	$	411	$	401	2	%
Depreciation, depletion and amortization	$	2,870	$	212	1254	%
General and administrative expenses	$	1,342	$	1,103	22	%
Interest expense, net of interest capitalized	$	830	$	167	397	%
Interest income	$	364	$	252	44	%
Other income	$	2,123	$	84	2427	%

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

Natural Gas, Oil and Natural Gas Liquids (“NGL”) Sales. We reported revenues of approximately $14.1 million for the three months ended September 30, 2007, compared to revenues of approximately $1.2 million for the three months ended September 30, 2006. This increase is mainly attributable to our Dutch #1 discovery which began producing in January 2007, our Dutch #2 discovery which began producing in July 2007, and increased production from our Arkansas Fayetteville Shale play.

For the three months ended September 30, 2007 and September 30, 2006, prices for natural gas were $5.83 per thousand cubic feet (“Mcf”) and $6.25, respectively, while the blended price for oil and NGLs was $54.99 per barrel and $70.21 per barrel, respectively.

Natural Gas and Oil Production and Average Sales Prices. Our net natural gas production for the three months ended September 30, 2007 was approximately 22.4 Mmcf/d of natural gas, up from approximately 1.6 Mmcf/d of natural gas for the three months ended September 30, 2006. Net oil and NGL production for the comparable periods also increased from approximately 44 barrels per day to approximately 414 barrels per day. This increase in natural gas production is principally attributable to Dutch #1 which began producing in January 2007, Dutch #2 which began producing in July 2007, and increased production from our Arkansas Fayetteville Shale play. The increase in oil and NGL production is principally attributable to our Dutch discoveries.

Operating Expenses. Lease operating expenses for the three months ended September 30, 2007 and the three months ended September 30, 2006 were approximately $1.7 million and $132,949, respectively. These expenses are related to our onshore activities in the Arkansas Fayetteville Shale and our offshore activities in the Gulf of Mexico. The increase is attributable to increased activities in both areas.

Exploration Expense. We reported approximately $411,389 of exploration expenses for the three months ended September 30, 2007, which was attributable to the cost of various geological and geophysical activities, seismic data, dry holes and delay rentals. We reported approximately $401,347 million of exploration expenses for the three months ended September 30, 2006, which was 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 September 30, 2007 was approximately $2.9 million. For the three months ended September 30, 2006, we recorded $212,191 of depreciation, depletion and amortization. The increase is the result of production from our Dutch #1 well which began producing in January 2007, our Dutch #2 well which began producing in July 2007, and the Arkansas Fayetteville Shale play.

General and Administrative Expenses. General and administrative expenses for the three months ended September 30, 2007 and the three months ended September 30, 2006 were approximately $1.3 million and $1.1 million, respectively.

Major components of general and administrative expenses for the three months ended September 30, 2007 included approximately $0.5 million in salaries and benefits, approximately $0.1 million in legal, accounting, engineering and other professional fees, approximately $0.1 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 September 30, 2006 included approximately $0.5 million in salaries and benefits, $0.1 million in legal, accounting, engineering and other professional fees, $0.2 million in office administration expenses, $0.1 million in insurance costs, and $0.2 million related to the cost of expensing stock options and stock grant compensation.

Interest Expense. We reported interest expense of $829,860, net of approximately $328,714 of interest capitalized, for the three months ended September 30, 2007, compared to interest expense of $167,471, net of approximately $152,259 of interest capitalized, for the three months ended September 30, 2006. 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 $364,314 for the three months ended September 30, 2007. This compares to the $251,659 of interest income reported for the three months ended September 30, 2006. The increase is due to additional interest income from loans made to affiliates.

Other Income. For the three months ended September 30, 2007, we reported other income of approximately $2.1 million. Of this amount, approximately $2.2 million was received from a private investor, offset by a credit of $0.1 million related to our non-Arkansas onshore properties. In September 2007, one of our stockholders determined that it had inadvertently engaged in trades which resulted in automatic short swing profit liability to the Company pursuant to Section 16(b) of the Securities Exchange Act of 1934. After becoming aware of the situation, the stockholder promptly made a payment of approximately $2.2 million to the Company to settle the entire short swing profit liability owed as a consequence of these trades. For the three months ended September 30, 2006, we reported other income of $84,391 resulting from changes in the market value of Protonex and equity earnings from Moblize.

Production, Prices, Operating Expenses, and Other


	Three Months Ended September 30,
	2007		2006
	(Dollar amounts in 000’s, except per Mcfe amounts)
Production Data:
Natural gas (million cubic feet)		2,065		144
Oil, condensate and NGLs (thousand barrels)		38		4
Total (million cubic feet equivalent)		2,293		168

Natural gas (million cubic feet per day)		22.4		1.6
Oil, condensate and NGLs (thousand barrels per day)		0.4		0.1
Total (million cubic feet equivalent per day)		24.8		2.2

Average sales price:
Natural gas (per thousand cubic feet)	$	5.83	$	6.25
Oil, condensate and NGLs (per barrel)	$	54.99	$	70.21

Selected data per Mcfe:
Production and severance taxes	$	0.02	$	0.27
Lease operating expenses	$	0.71	$	0.52
General and administrative expenses	$	0.59	$	6.54
Depreciation, depletion and amortization of natural gas and oil properties	$	1.19	$	1.00

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 to 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 three months ended September 30, 2007 was approximately $35.2 million, compared to cash flows provided by operating activities of approximately $6.8 million for the three months ended September 30, 2006. This increase in cash flows from operating activities is primarily attributable to increased natural gas and oil production and revenues.

Investing Activities. Cash flows used in investing activities for the three months ended September 30, 2007 was approximately $37.2 million, compared to $13.1 million for the same period in 2006. This $24.1 million increase in capital expenditures is primarily attributable to investing approximately $18.8 million more on natural gas and oil properties. Natural gas and oil exploration and development expenditures were approximately $41.1 million for the three months ended September 30, 2007, compared to $22.3 million for the three months ended September 30, 2006.

Financing Activities. Our financing activities provided approximately $4.7 million in cash flow for the three months ended September 30, 2007 compared to using $0.3 million for the same period in 2006. This increase is primarily attributable to borrowing by our affiliates of $4.7 million, net to Contango.

Capital Budget. For fiscal year 2008, our capital expenditure budget calls for us to invest approximately $25.6 million in onshore activities as we continue to develop our Arkansas Fayetteville Shale play, and approximately $30.0 million in offshore activities as we bring Dutch #3 and Mary Rose #1 to production, and drill an additional three to four developmental wells on our Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) prospects. We anticipate we will need a total of seven to nine wells to fully develop this discovery. Additionally, we are building an associated platform and pipeline and have budgeted to drill at least one additional wildcat exploration offshore well. 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. REX’s capital needs are provided by a private investment company pursuant to a $50.0 million demand note which is non-recourse to the Company, $41.0 million of which is currently outstanding. We believe this REX Demand Note together with anticipated cash flows available to REX will provide REX with sufficient liquidity to meet its obligations.

Of the $30.0 million in offshore capital expenditures budgeted for fiscal year 2008, approximately $5.5 million was invested during the three months ended September 30, 2007. Of this, approximately $1.7 million was invested in production and pipeline facilities for developing Dutch #3 and bringing it to production, approximately $2.9 million was invested in completion and hookup costs for Mary Rose #1, approximately $0.4 million was invested for a platform and 20-inch, 20-mile pipeline we are building at Eugene Island 11, and approximately $0.5 million was invested on projected follow-on developmental wells and upgrades to the Eugene Island 24 platform.

Of the $25.6 million in onshore capital expenditures budgeted for fiscal year 2008, we invested approximately $8.5 million in the Arkansas Fayetteville Shale during the three months ended September 30, 2007. We have committed to a total of 181 wells in this play as of October 31, 2007. Of these 181 wells, 29 are or will be operated by Alta and 152 are or will be operated by a third party independent oil and gas exploration company (“Integrated Wells”). Our working interest and net revenue interest have averaged approximately 11% and 10%, respectively, in these 181 wells.

We are budgeting to drill one Alta-operated well per month. During the three months ended September 30, 2007, we invested $5.3 in Alta-operated wells. This includes drilling, fracture stimulating, completion and hookup costs for various wells, including wells spud during fiscal year 2007. For the Integrated Wells, we are budgeting to receive four Authorities for Expenditures (“AFEs”) for Integrated Wells per month during fiscal year 2008. We anticipate having between 120 to 130 producing Integrated Wells by December 2007. For the three months ended September 30, 2007, we invested approximately $3.2 in Integrated Wells. This includes drilling, fracture stimulating, completion and hookup costs for various wells, including wells spud during fiscal year 2007.

The Company had estimated production as of November 6, 2007 of approximately 33.0 Mmcfe/d.

Contango and 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 and Arkansas Fayetteville Shale development programs. 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 September 30, 2007. 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 September 30, 2007 was determined by the September 30, 2007 prices of $6.38 per MMbtu for natural gas at Henry Hub and $81.66 per barrel of oil at West Texas Intermediate Posting, in each case before adjustments.


	Proved Reserves as of September 30, 2007
Natural Gas (MMcf)		116,780
Oil and Condensate (MBbls)		1,923
Total proved reserves (Mmcfe)		128,318

Pre-tax net present value, SEC guidelines ($ 000)	$	492,416

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 January 30, 2007, the Company completed the arrangement of a $30.0 million secured term loan agreement with a private investment firm (the “Term Loan Agreement”). The Term Loan Agreement is secured with substantially all the assets of the Company, except for the stock of Contango Sundance, Inc. (“Sundance”), our wholly-owned subsidiary. As of September 30, 2007, the Company had no amounts borrowed under the Term Loan Agreement. Borrowings under the Term Loan Agreement bear interest at 30 day LIBOR plus 5.0%. Accrued interest is due monthly. The principal is due December 31, 2008, but we may prepay at any time with no prepayment penalty. An arrangement fee of 1%, or $300,000, was paid in connection with the term loan. Additionally, we pay a non-use fee in the amount of 1.50% per annum multiplied by such non-funded amount.

Borrowings under the RBS Facility bear interest, at the Company’s option, at either (i) 30 day LIBOR, (ii) 60 day LIBOR, (iii) 90 day LIBOR or (iv) 6 month LIBOR, all plus 6.5%. Interest is due at the end of the LIBOR period chosen. The principal is due April 27, 2009, but we may prepay after April 27, 2008 with no prepayment penalty.

Both the Term Loan Agreement and the RBS Facility require a minimum level of working capital and contain 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 and RBS Facility 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 September 30, 2007, the Company was in compliance with its financial covenants, ratios and other provisions of the Term Loan Agreement and RBS Facility.

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:

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The domestic and foreign supply of natural gas and oil.

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Overall economic conditions.

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The level of consumer product demand.

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Adverse weather conditions and natural disasters.

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

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

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The level of LNG imports.

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Domestic and foreign governmental regulations.

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Potential price controls and special taxes.

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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 $87.0 million in proceeds from eight 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 prospects. Although as a company we have previously taken working interests in offshore prospects, our recent exploration prospects 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 Dutch #1 and Dutch #2 wells, and as we prepare to begin production at our Dutch #3 well, 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 and Dutch #2 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 have significant resources committed to our Arkansas Fayetteville Shale play.

Our Arkansas Fayetteville Shale play proved reserves at September 30, 2007 were approximately 16.3 Bcf. Since inception, we have expended approximately $57.5 million in the Fayetteville Shale play ($9.6 million in lease acquisitions, $43.6 million in drilling and completion activities and $4.3 million in dry hole costs), while our revenues from the play from inception through the production month of September 2007 have totaled only $8.8 million. There can be no assurance that our drilling activity in this area will produce economically feasible wells. Our capital budget for the remainder of fiscal year 2008 calls for us to invest an additional $17.1 million in the Arkansas Fayetteville Shale. We intend to continue to borrow significant capital against anticipated revenues and production, and should the wells not perform as expected, we could encounter difficulty repaying this debt. It is early in the exploration and development of this play, there is a lack of oil field service infrastructure in the area, and we are still learning how to most efficiently drill, complete, fracture stimulate and produce these wells. Some of our wells have taken considerably longer than expected to drill, and we have had significant cost overruns. All of our wells are operated by others and as a result, we have a limited ability to exercise influence over operations or their associated costs.

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

Our $30.0 million Term Loan Agreement and REX’s $50.0 million demand note are with the same private investment firm. Contango had no amounts outstanding under the Term Loan Agreement and REX had borrowed $41.0 million under its demand note as of October 31, 2007. Should the private investment firm encounter difficulties funding future requested advances, some portion or all of the $39.0 million of 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.

REX’s $50 million note is payable upon demand by the lender.

REX’s $50.0 million demand note with the private investment firm is payable upon demand. Should the private investment firm decide to call the note, REX does not have the funds available to repay its borrowings. In that case, REX would be forced to seek alternative and possibly more expensive financing, which may or may not be available, or risk losing the assets it has pledged as collateral, including its interest in the Dutch and Mary Rose prospects.

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 two highly capital intensive prospect areas which increases our risk of incurring significant losses.

Beginning in the spring of 2005, we have continued to increase our capital investment in just two exploration prospects, our onshore Arkansas Fayetteville Shale prospect and our offshore Gulf of Mexico prospects. Both of these investments represent a major increase in the risk profile of the Company.

The construction of our LNG receiving terminal in Freeport, Texas is subject to various development and completion risks.

We own a 10% limited partnership interest in the Freeport LNG receiving facility being constructed in Freeport, Texas. The LNG project received approval from the Federal Energy Regulatory Commission (the “FERC”) in June 2004. On January 11, 2005, Freeport LNG received its authorization to commence construction of the first phase of its terminal from the FERC. Construction of the 1.75 Bcf/d facility commenced on January 17, 2005. Freeport LNG received FERC authorization in September 2006 for an expansion that would increase the permitted capacity from its current level of 1.75 Bcf/d up to as much as 4.0 Bcf/d. The LNG receiving facility is subject to development risk such as permitting, cost overruns and delays. Key factors that may affect the completion of the LNG receiving terminal include, but are not limited to: timely issuance of necessary additional permits, licenses and approvals by governmental agencies and third parties; sufficient financing; unanticipated changes in market demand or supply; competition with similar projects; labor disputes; site difficulties; environmental conditions; unforeseen events, such as hurricanes, explosions, fires and product spills; delays in manufacturing and delivery schedules of critical equipment and materials; resistance in the local community; local and general economic conditions; and commercial arrangements for pipelines and related equipment to transport and market LNG.

If completion of the LNG receiving facility is delayed beyond the estimated development period, the actual cost of completion may increase beyond the amounts currently estimated in our capital budget. A delay in completion of the LNG receiving facility would also cause a delay in the receipt of revenues projected from operation of the facility, which may cause our business, results of operations and financial condition to be substantially harmed.

If we are not able to fund or finance our 10% ownership in the LNG receiving terminal in Freeport, Texas, including any expansion of the terminal, we may lose our 10% investment in the project.

A majority of the Freeport LNG construction costs is being provided by The ConocoPhillips Company. Upon any significant increase in construction costs to complete construction of the receiving terminal or upon a call to fund construction of the proposed expansion, we may not have the financial resources to fund our 10% ownership share of construction costs. If we are unable to fund our share of the project costs or if the project is unable to secure third-party project financing, we could lose our investment in the project or be forced to sell our interest in an untimely fashion or on less than favorable terms.

If we default on our loan from The Royal Bank of Scotland plc we could lose our 10% investment in the LNG receiving terminal in Freeport, Texas.

Our three-year $20.0 million term loan agreement dated April 27, 2006 with The Royal Bank of Scotland plc is secured with the stock of Contango Sundance, Inc. (“Sundance”), our wholly-owned subsidiary. Sundance owns a 10% limited partnership interest in Freeport LNG Development, LP, which owns the Freeport LNG terminal. If an event of default occurs under the term loan agreement, we could lose our investment in the Freeport LNG terminal.

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 SEC 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 two producing well bores that, as of October 31, 2007, had only nine months of production history. Reserve assessments based on only two 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:

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Unexpected drilling conditions.

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

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Pressure or irregularities in formations.

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Equipment failures or accidents.

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Tropical storms, hurricanes and other adverse weather conditions.

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Compliance with governmental requirements and laws, present and future.

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

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

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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:

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Blowouts, fires and explosions.

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Surface cratering.

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

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Natural disasters.

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Pipe and cement failures.

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Casing collapses.

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Stuck drilling and service tools.

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Abnormal pressure formations.

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

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

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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:

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Injury or loss of life.

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Reservoir damage.

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Severe damage to and destruction of property or equipment.

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Pollution and other environmental damage.

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Clean-up responsibilities.

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Regulatory investigations and penalties.

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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 most 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:

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Require that we obtain permits before commencing drilling.

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

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

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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:

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Timing and amount of capital expenditures.

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The operator’s expertise and financial resources.

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Approval of other participants in drilling wells.

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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:

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Recoverable reserves.

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Exploration potential.

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Future natural gas and oil prices.

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Operating costs.

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Potential environmental and other liabilities and other factors.

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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:

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Problems integrating the purchased operations, personnel or technologies.

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Unanticipated costs.

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Diversion of resources and management attention from our exploration business.

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

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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:

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

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Limit the personal liability of directors.

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Limit the persons who may call special meetings of stockholders.

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Prohibit stockholder action by written consent.

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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.

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

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Impose restrictions on business combinations with some interested parties.

Our common stock is thinly traded.

Contango has approximately 16.0 million shares of common stock outstanding, held by approximately 150 holders of record. Directors and officers own or have voting control over approximately 2.8 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 September 30, 2007, we had approximately $8.9 million in cash and cash equivalents. Of this, approximately $8.7 million was held in our operating accounts to be used for general corporate purposes, and approximately $0.2 million was invested in highly liquid AAA-rated tax-exempt money market funds. Our money market funds are highly liquid AAA-rated tax-exempt securities with maturities of 90 days or less. 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 September 30, 2007, 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 September 30, 2007, a 10% fluctuation in the prices received for natural gas and oil production would impact our revenues by approximately $1.4 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 September 30, 2007. Based upon that evaluation, the Company’s management concluded that, as of September 30, 2007, 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 September 30, 2007 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)

3.1		Certificate of Incorporation of Contango Oil & Gas Company. (4)

3.2		Bylaws of Contango Oil & Gas Company. (4)

3.3		Agreement of Plan of Merger of Contango Oil & Gas Company, a Delaware corporation, and Contango Oil & Gas Company, a Nevada corporation. (4)

3.4		Amendment to the Certificate of Incorporation of Contango Oil & Gas Company. (5)

4.1		Facsimile of common stock certificate of Contango Oil & Gas Company. (6)

4.2		Certificate of Designations, Preferences and Relative Rights and Limitations for Series E Perpetual Cumulative Convertible Preferred Stock of Contango Oil & Gas Company. (7)

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. (7)

23.1		Consent of W.D. Von Gonten & Co. †

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 December 1, 2000, as filed with the Securities and Exchange Commission on December 15, 2000.

5.	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.

6.	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.

7.	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.

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: November 8, 2007	By:	/s/ KENNETH R. PEAK
		Kenneth R. Peak
		Chairman, Chief Executive Officer and
		Chief Financial Officer
		(Principal Executive and Financial Officer)

Date: November 8, 2007	By:	/s/ LESIA BAUTINA
		Lesia Bautina
		Senior Vice President and Controller
		(Principal Accounting Officer)