CONTANGO OIL & GAS CO - 10-Q Quarterly Report

Back to GetFilings.com

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2004

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

(Issuer’s telephone number)

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 an accelerated filer (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 May 12, 2004 was 12,110,700.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE NINE MONTHS ENDED MARCH 31, 2004

TABLE OF CONTENTS


		Page
PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements
Consolidated Balance Sheets as of March 31, 2004 and June 30, 2003		3
Consolidated Statements of Operations for the three and nine months ended March 31, 2004 and 2003		5
Consolidated Statements of Cash Flows for the nine months ended March 31, 2004 and 2003		6
Consolidated Statement of Shareholders’ Equity for the nine months ended March 31, 2004 and 2003		7
Notes to the Consolidated Financial Statements		9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18
Item 3. Quantitative and Qualitative Disclosures about Market Risk		40
Item 4. Controls and Procedures		40

PART II – OTHER INFORMATION

Item 1. Legal Proceedings		40
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		40
Item 3. Defaults Upon Senior Securities		40
Item 4. Submission of Matters to a Vote of Security Holders		40
Item 5. Other Information		40
Item 6. Exhibits and Reports on Form 8-K		41

All references in this Form 10-Q to the “Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas Company and 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.

WEBSITE ACCESS TO REPORTS

General information about us can be found on our Website at www.contango.com. Our annual reports on Form 10-KSB, quarterly reports on Form 10-Q, Form 10-QSB 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.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS


	March 31, 2004			June 30, 2003
	(Unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	339,002		$	219,242
Accounts receivable, net		4,385,623			6,039,779
Prepaid capital costs		199,005			—
Marketable equity securities		—			676,500
Other		155,370			96,115

Total current assets		5,079,000			7,031,636

PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties		53,180,138			55,125,109
Unproved properties, not being amortized		3,959,677			3,065,188
Furniture and equipment		130,524			126,388
Accumulated depreciation, depletion and amortization		(25,486,409	)		(21,574,673	)

Total property, plant and equipment, net		31,783,930			36,742,012

OTHER ASSETS:
Cash held by affiliates		2,571,278			784,656
Investment in Freeport LNG Project		1,750,000			850,000
Investment in partnership		—			72,500
Deferred income tax asset		1,000,650			568,024
Facility fee		177,279			177,500
Other assets		101,379			78,612

Total other assets		5,600,586			2,531,292

TOTAL ASSETS	$	42,463,516		$	46,304,940

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY


	March 31, 2004			June 30, 2003
	(Unaudited)
CURRENT LIABILITIES:
Accounts payable	$	410,661		$	681,425
Accrued exploration and development		—			1,011,098
Income taxes payable		1,098,856			734,312
Price hedge contracts		—			58,171
Short term hedge payable		—			102,486
Other accrued liabilities		445,535			229,937
Current portion of long-term debt		—			5,890,000

Total current liabilities		1,955,052			8,707,429

LONG-TERM DEBT		3,850,528			16,460,000

ASSET RETIREMENT OBLIGATION		85,582			191,664

DEFERRED CREDITS		—			208,333

SHAREHOLDERS’ EQUITY:
Convertible preferred stock, 8%, Series A, $0.04 par value, 5,000 shares authorized, 2,500 shares issued and outstanding at June 30, 2003, liquidation preference of $1,000 per share		—			100
Convertible preferred stock, 8%, Series B, $0.04 par value, 10,000 shares authorized, 5,000 shares issued and outstanding at June 30, 2003, liquidation preference of $1,000 per share		—			200
Convertible preferred stock, 6%, Series C, $0.04 par value, 4,000 shares authorized, 1,600 shares issued and outstanding at March 31, 2004, liquidating preference of $5,000 per share		64			—
Common stock, $0.04 par value, 50,000,000 shares authorized, 14,675,700 shares issued and 12,100,700 outstanding at March 31, 2004, 11,871,076 shares issued and 9,296,076 outstanding at June 30, 2003		571,204			473,399
Additional paid-in capital		29,339,791			21,803,090
Treasury stock at cost (2,575,000 shares)		(6,180,000	)		(6,180,000	)
Retained earnings		12,841,295			4,640,725

Total shareholders’ equity		36,572,354			20,737,514

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	42,463,516		$	46,304,940

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 March 31,						Nine Months Ended March 31,
	2004			2003			2004			2003
REVENUES:
Natural gas and oil sales	$	6,611,139		$	10,061,351		$	20,843,951		$	24,793,109
Gain (loss) from hedging activities		—			(5,230,672	)		58,171			(5,416,998	)

Total revenues		6,611,139			4,830,679			20,902,122			19,376,111

EXPENSES:
Operating expenses		493,008			1,448,367			3,061,922			4,179,166
Exploration expenses		1,737,499			3,588,654			5,225,497			15,496,798
Depreciation, depletion and amortization		1,747,527			1,942,144			5,160,262			6,518,654
Impairment of natural gas and oil properties		—			—			42,995			—
General and administrative expenses		662,898			391,483			1,808,478			1,464,576

Total expenses		4,640,932			7,370,648			15,299,154			27,659,194

INCOME (LOSS) FROM OPERATIONS		1,970,207			(2,539,969	)		5,602,968			(8,283,083	)

Interest expense		(28,804	)		(177,860	)		(308,449	)		(531,763	)
Interest income		12,263			6,498			31,929			27,663
Gain on sale of marketable securities		—			—			710,322			—
Gain on sale of assets and other		128,904			—			7,245,314			36,150

INCOME (LOSS) BEFORE INCOME TAXES		2,082,570			(2,711,331	)		13,282,084			(8,751,033	)

(Provision) benefit for income taxes		(728,900	)		948,966			(4,581,514	)		3,061,216

NET INCOME (LOSS)		1,353,670			(1,762,365	)		8,700,570			(5,689,817	)
Preferred stock dividends		173,333			150,000			500,000			450,000

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	1,180,337		$	(1,912,365	)	$	8,200,570		$	(6,139,817	)

NET INCOME (LOSS) PER SHARE:
Basic	$	0.11		$	(0.21	)	$	0.83		$	(0.68	)

Diluted	$	0.09		$	(0.21	)	$	0.67		$	(0.68	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		11,145,896			9,158,755			9,927,796			9,080,392

Diluted		14,392,811			9,158,755			13,029,200			9,080,392

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended March 31,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	8,700,570		$	(5,689,817	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		5,160,262			6,518,654
Impairment of natural gas and oil properties		42,995			—
Exploration expenditures		5,099,292			4,578,620
Deferred income taxes		(432,626	)		(4,632,215	)
Gain on sale of assets and other		(7,955,636	)		(36,150	)
Unrealized hedging gain		(58,171	)		(88,292	)
Stock-based compensation		129,047			81,628
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable and other		1,654,156			(1,650,613	)
(Increase) decrease in prepaid insurance		(90,024	)		87,132
Decrease in accounts payable		(581,583	)		(216,733	)
Decrease in other accrued liabilities		(233,534	)		(744,269	)
(Decrease) increase in income taxes payable		364,544			(590,788	)
Other		128,172			(37,660	)

Net cash provided (used) by operating activities		11,927,464			(2,420,503	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures		(5,191,749	)		(2,559,416	)
(Increase) decrease in net investments in affiliates		(2,506,293	)		900,000
Investment in Freeport LNG Project		(900,000	)		—
Additions to furniture and equipment		(4,136	)		(16,238	)
(Increase) decrease in advances to operators		(730,059	)		557,560
Purchase of proved producing reserves		—			(2,599,485	)
Purchase of marketable equity securities		(375,000	)		—
Proceeds from sales of marketable equity securities		1,761,822			—
Acquisition costs		—			(3,100	)
Sales costs		(5,281	)		—
Proceeds from the sale of assets		7,766,379			—

Net cash (used) provided in investing activities		(184,317	)		(3,720,679	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		14,232,528			22,065,000
Repayments under credit facility		(32,732,000	)		(17,525,000	)
Proceeds from equity issuances		8,186,583			456,000
Preferred stock dividends		(500,000	)		(450,000	)
Repurchase/cancellation of stock options and warrants		(757,498	)		—
Debt issue costs		(53,000	)		(46,250	)

Net cash (used) provided in financing activities		(11,623,387	)		4,499,750

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		119,760			(1,641,432	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		219,242			2,726,845

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	339,002		$	1,085,413

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for taxes	$	4,271,184		$	2,405,788

Cash paid for interest	$	344,005		$	485,634

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Unaudited)


	For the Nine Months Ended March 31, 2003
	Preferred Stock			Common Stock			Paid-in Capital		Treasury Stock			Retained Earnings			Total Shareholders’ Equity
	Shares	Amount		Shares	Amount		Paid-in Capital		Treasury Stock			Retained Earnings			Total Shareholders’ Equity
Balance at June 30, 2002	7,500	$	300	9,043,282	$	464,732	$	21,236,701	$	(6,180,000	)	$	9,576,750		$	25,098,483
Expense of stock options	—		—	—		—		21,083		—			—			21,083
Net income	—		—	—		—		—		—			366,868			366,868
Preferred stock dividends	—		—	—		—		—		—			(150,000	)		(150,000	)

Balance at September 30, 2002	7,500		300	9,043,282		464,732		21,257,784		(6,180,000	)		9,793,618			25,336,434

Expense of stock options	—		—	—		—		31,944		—			—			31,944
Cashless exercise of stock options	—		—	9,595		—		—		—			—			—
Net loss	—		—	—		—		—		—			(4,294,320	)		(4,294,320	)
Preferred stock dividends	—		—	—		—		—		—			(150,000	)		(150,000	)

Balance at December 31, 2002	7,500	$	300	9,052,877	$	464,732	$	21,289,728	$	(6,180,000	)	$	5,349,298		$	20,924,058

Exercise of warrants	—		—	200,000		8,000		392,000		—			—			400,000
Federal tax benefit from the exercise of warrants	—		—	—		—		56,000		—			—			56,000
Cashless exercise of stock options	—		—	9,264		—		—		—			—			—
Expense of stock options	—		—	—		—		28,601		—			—			28,601
Net loss	—		—	—		—		—		—			(1,762,365	)		(1,762,365	)
Preferred stock dividends	—		—	—		—		—		—			(150,000	)		(150,000	)

Balance at March 31, 2003	7,500	$	300	9,262,141	$	472,732	$	21,766,329	$	(6,180,000	)	$	3,436,933		$	19,496,294

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Unaudited)


	For the Nine Months Ended March 31, 2004
	Preferred Stock					Common Stock			Paid-in Capital			Treasury Stock			Retained Earnings			Total Shareholders’ Equity
	Shares		Amount			Shares	Amount		Paid-in Capital			Treasury Stock			Retained Earnings			Total Shareholders’ Equity
Balance at June 30, 2003	7,500		$	300		9,296,076	$	473,399	$	21,803,090		$	(6,180,000	)	$	4,640,725		$	20,737,514
Exercise of stock options	—			—		3,750		150		7,350			—			—			7,500
Tax benefit from exercise of stock options	—			—		—		—		3,373			—			—			3,373
Cashless exercise of stock options	—			—		1,866		—		—			—			—			—
Expense of stock options	—			—		—		—		27,034			—			—			27,034
Repurchase/cancellation of stock options and warrants	—			—		—		—		(757,498	)		—			—			(757,498	)
Net income	—			—		—		—		—			—			3,058,491			3,058,491
Preferred stock dividends	—			—		—		—		—			—			(150,000	)		(150,000	)

Balance at September 30, 2003	7,500			300		9,301,692		473,549		21,083,349			(6,180,000	)		7,549,216			22,926,414

Exercise of stock options	—			—		118,750		4,750		232,750			—			—			237,500
Tax benefit from exercise of stock options	—			—		—		—		16,629			—			—			16,629
Cashless exercise of stock options	—			—		18,067		—		—			—			—			—
Issuance of Series C preferred stock	1,600			64		—		—		7,554,550			—			—			7,554,614
Expense of stock options	—			—		—		—		50,349			—			—			50,349
Net income	—			—		—		—		—			—			4,288,409			4,288,409
Preferred stock dividends	—			—		—		—		—			—			(176,667	)		(176,667	)

Balance at December 31, 2003	9,100			364		9,438,509		478,299		28,937,627			(6,180,000	)		11,660,958			34,897,248

Exercise of stock options	—			—		186,250		7,450		379,519			—			—			386,969
Tax benefit from exercise of stock options	—			—		—		—		56,136			—			—			56,136
Cashless exercise of stock options and warrants	—			—		339,577		—		—			—			—			—
Conversion of Series A preferred stock and Series B preferred stock to common stock	(7,500	)		(300	)	2,136,364		85,455		(85,155	)		—			—			—
Expense of stock options	—			—		—		—		51,664			—			—			51,664
Net income	—			—		—		—		—			—			1,353,670			1,353,670
Preferred stock dividends	—			—		—		—		—			—			(173,333	)		(173,333	)

Balance at March 31, 2004	1,600		$	64		12,100,700	$	571,204	$	29,339,791		$	(6,180,000	)	$	12,841,295		$	36,572,354

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 consolidated financial statements have been prepared in conformity with generally accepted accounting principles in the United States for interim financial information and pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, they do not include all the information and footnotes required by generally accepted accounting principles 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 Contango Oil & Gas Company’s (“Contango” or the “Company”) Form 10-KSB for the fiscal year ended June 30, 2003. The results of operations for the three and nine months ended March 31, 2004 are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2004.

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 critical accounting principles, which are described below, relate to the successful efforts method for costs related to natural gas and oil activities, consolidation principles, accounting for financial instruments and stock options.

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 cash flows on a cost center basis to the unamortized capitalized cost of the asset. If the future undiscounted 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.

On July 1, 2003, the Company changed its accounting policy for amortizing and impairing the Company’s natural gas and oil properties from a well-by-well cost center basis to a field-by-field cost center basis. Management believes the newly adopted policy is preferable in the circumstances to have greater comparability with other successful efforts natural gas and oil companies by conforming to predominant industry practice. In addition, the field level is consistent with the Company’s operational and strategic assessment of its natural gas and oil investments. The Company determined that the cumulative effect of the change in accordance with APB Opinion No. 20 was immaterial to the consolidated financial statements.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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. Subsidiaries not wholly owned, such as 33.3% owned Republic Exploration LLC (“Republic Exploration”), 50.0% owned Magnolia Offshore Exploration LLC (“Magnolia Offshore Exploration”) and 66.7% owned Contango Offshore Exploration LLC (“Contango Offshore Exploration”) are not controlled by the Company and are proportionately consolidated. By agreement, Republic Exploration, Magnolia Offshore Exploration and Contango Offshore Exploration have disproportionate allocations of their profits and losses among the owners. Accordingly, the Company determines its income or losses from the ventures based on a hypothetical liquidation determination of how increases or decreases in the book value of the ventures’ net assets will ultimately affect the cash payments to the Company in the event of dissolution.

During the quarter ended December 31, 2002, both Republic Exploration and Magnolia Offshore Exploration completed exploration activities to fully expend the Company’s initial cash contributions to the ventures thereby triggering a change in profit and loss allocations. This triggering event earned the other partners in Republic Exploration and Magnolia Offshore Exploration the right to receive their proportionate share of the Company’s initial investment in Republic Exploration and Magnolia Offshore Exploration. As such, the Company proportionately consolidated 33.3% of Republic Exploration’s and 50.0% of Magnolia Offshore Exploration’s net assets as of December 31, 2002, as opposed to 100% of each ventures’ net assets as of September 30, 2002. The reduction of the Company’s ownership in the net assets of Republic Exploration and Magnolia Offshore Exploration resulted in a non-cash exploration expense of approximately $4.2 million and approximately $200,000, respectively. The Company’s cash contributions to Contango Offshore Exploration during the quarter ended December 31, 2002 that were expended for geological and geophysical data resulted in an approximate $4.1 million exploration expense. The Company’s proportionate share of the ventures’ cash balances is classified as other long-term assets since it is expected those funds will be expended for their intended purposes.

By agreement, since the Company was the only owner that contributed cash to Republic Exploration and Magnolia Offshore Exploration, the Company consolidated 100% of the ventures’ net assets and results of operations until the ventures expended all of the Company’s initial cash contributions. Subsequent to that event, the owners’ share in the net assets of the ventures is based on their stated ownership percentages. By agreement, the owners in Contango Offshore Exploration immediately share in the net assets of Contango Offshore Exploration, including the initial Company cash contribution, based on their stated ownership percentages. The other owners of Republic Exploration, Magnolia Offshore Exploration and Contango Offshore Exploration contributed seismic data and related geological and geophysical services to the ventures.

Recent Accounting Pronouncements. The Financial Accounting Standards Board (“FASB”) has issued several new pronouncements, including Interpretation No. 46 (revised December 2003) (“FIN 46R”), “Consolidation of Variable Interest Entities, an interpretation of ARB 51”, Statement of Financial Accounting Standards No. 149 (“SFAS 149”), “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” and Statement of Financial Accounting Standards No. 150 (“SFAS 150”), “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

“variable interest entities” or “VIEs”) and how to determine if a business enterprise should consolidate the VIEs. This new model for consolidation applies to an entity for which either:

•

the equity investors (if any) do not have a controlling financial interest; or

•

the equity investment at risk is insufficient to finance the entity’s activities without receiving additional subordinated financial support from other parties.

In addition, FIN 46R requires that all enterprises with a significant variable interest in a VIE make additional disclosures regarding their relationship with the VIE. The interpretation requires public entities to apply FIN 46R to all entities that are considered special purpose entities in practice and under the FASB literature that was applied before the issuance of FIN 46R by the end of the first reporting period that ends after December 15, 2003. Application of the accounting requirements of the interpretation to all other entities is required by the end of the first reporting period that ends after March 15, 2004. The adoption of FIN 46R had no effect on the Company’s financial statements.

SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and hedging activities under SFAS 133. The amendments set forth in SFAS 149 require that contracts with comparable characteristics be accounted for similarly. SFAS 149 is generally effective for contracts entered into or modified after June 20, 2003 (with limited exceptions) and for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively only. The adoption of SFAS 149 had no effect on the Company’s financial statements.

SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. It was to be implemented by reporting the cumulative effect of a change in an accounting principle for financial instruments created before the issuance date of SFAS 150 and still existing at the beginning of the interim period of adoption. Restatement is not permitted. The adoption of SFAS 150 did not have an impact on the Company’s consolidated financial position or results of operations.

Stock-Based Compensation. Prior to the fiscal year-ended June 30, 2002, the Company accounted for employee stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”. Under the intrinsic method, compensation cost for stock options is measured as the excess, if any, of the fair value of the Company’s common stock at the date of the grant over the amount an employee must pay to acquire the common stock.

Effective July 1, 2001, the Company prospectively changed its method of accounting for employee stock-based compensation to the fair value based method prescribed in Statement of Financial Accounting Standards 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 options-pricing model.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The Company has determined that the fair value method is preferable to the intrinsic value method previously applied. During the nine months ended March 31, 2004 and 2003, the Company recorded a charge of $129,047 and $81,628 to general and administrative expense, respectively. Because compensation expense is recognized over a vesting period, the effect of applying the fair value method in the initial years of implementation may not be representative of the effects on net income (loss) that will be reported in future years.

Derivative Instruments and Hedging Activities. Contango has periodically entered into commodity derivatives contracts and fixed-price physical contracts to manage its exposure to natural gas and oil price volatility. Commodity derivatives contracts, which are usually placed with investment grade companies that the Company believes is a minimal credit risk, may take the form of futures contracts, swaps or options. The natural gas and oil reference prices upon which these commodity derivatives contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company.

In June 1998, the FASB issued SFAS 133, “Accounting for Derivative Instruments and Hedging Activities”. SFAS 133 established accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts), as defined, be recorded in the balance sheet as either an asset or liability measured at fair value and requires that changes in fair value are recognized in earnings unless specific hedge accounting criteria are met.

The table below sets forth the Company’s hedging activities for the periods indicated:


	Three Months Ended									YTD Total March 31, 2004
	September 30, 2003			December 31, 2003			March 31, 2004			YTD Total March 31, 2004
Mark-to-market reversal of prior period unrealized recognized (gain) loss	$	58,171		$	(24,071	)	$	—		$	58,171
Mark-to-market gain unrealized		24,071			—			—			—

Gain (loss) from hedging activities	$	82,242		$	(24,071	)	$	—		$	58,171


	Three Months Ended									YTD Total March 31, 2003
	September 30, 2002			December 31, 2002			March 31, 2003			YTD Total March 31, 2003
Mark-to-market reversal of prior period unrealized recognized loss (gain)	$	125,674		$	228,615		$	(759,887	)	$	125,674
Net cash received (paid) from swap settlements/options purchased		109,585			(1,181,472	)		(4,433,403	)		(5,505,290	)
Mark-to-market gain (loss) unrealized		(228,615	)		759,887			(37,382	)		(37,382	)

Gain (loss) from hedging activities	$	6,644		$	(192,970	)	$	(5,230,672	)	$	(5,416,998	)

Although the Company’s hedging transactions generally are designed as economic hedges for a portion of future natural gas and oil production, the Company has elected not to designate the derivative instruments as “hedges” under SFAS 133. As a result, gains and losses, representing changes in these derivative instruments’ mark-to-market fair values, were recognized in the Company’s earnings (see footnote 6 for more information on hedging activities).

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The Company had no open commodity derivative contracts at March 31, 2004.

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. Other factors that have a direct bearing on the Company’s prospects 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; 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.

3. Liquidity

Management believes that cash on hand, anticipated cash flow from operations and availability under the Company’s bank credit facility (see footnote 4), will be adequate to satisfy planned capital expenditures to fund drilling activities and to satisfy general corporate needs over the next twelve months. The Company may continue to seek additional equity or other financing to fund the Company’s exploration program and to take advantage of other opportunities that may become available. The availability of such funds will depend upon prevailing market conditions and other factors over which the Company has no control, as well as the Company’s financial condition and results of operations. There can be no assurances that the Company will have sufficient funds available to finance its intended exploration and development programs or acquisitions. The Company’s exploration drilling program could be adversely affected if sufficient funds are unavailable.

4. Long-Term Debt

Contango’s credit facility is a secured, reducing revolving line of credit with Guaranty Bank, FSB, secured by the Company’s natural gas and oil reserves. On February 13, 2004, the borrowing base was redetermined to $25.0 million in two tranches. Tranche A provides for a borrowing base of $23.0 million and matures on June 29, 2006. This amount reduces by $520,000 per month the first day of each month beginning March 1, 2004. Borrowings under Tranche A bear interest, at the Company’s option, at either (i) LIBOR plus two percent (2%) or (ii) the bank’s base rate plus one-fourth percent (1/4%) per annum. Additionally, the Company pays a quarterly commitment fee of three-eighths percent (3/8%) per annum on the average availability of Tranche A. Tranche B provides for a borrowing base of $2.0 million and matures on August 1, 2004. Borrowings under Tranche B will reduce by $520,000 per month the first day of each month following the date of borrowing, with the final reduction on August 1, 2004. Further, any amounts borrowed and repaid under Tranche B cannot be reborrowed. Borrowings under Tranche B bear interest, at the Company’s option, at either (i) LIBOR plus three percent (3%) or (ii) the bank’s base rate plus three-quarters percent (3/4%) per annum. Additionally, the Company pays a quarterly commitment fee of one-half percent (1/2%) per annum on the average availability under Tranche B.

The hydrocarbon borrowing base is subject to semi-annual redetermination based primarily on the value of the Company’s proved reserves. The credit facility requires the maintenance of certain ratios,

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

including those related to working capital, funded debt to EBITDAX, and debt service coverage, as defined in the credit facility. Additionally, the credit facility contains certain negative covenants that, among other things, restrict or limit the Company’s ability to incur indebtedness, sell assets, pay dividends and reacquire or otherwise acquire or redeem capital stock. Failure to maintain required financial ratios or comply with the credit facility’s covenants can result in a default and acceleration of all indebtedness under the credit facility.

As of March 31, 2004, the Company’s long-term debt totaled $3,850,528, all of which was outstanding under Tranche A of the line of credit. The average interest rate on the Company’s long-term debt at March 31, 2004 was 3.3%. As of March 31, 2004, the Company was in compliance with its financial covenants, ratios and other provisions of the credit facility.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

5. Net Income (Loss) Per Common Share

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


	Three Months Ended March 31, 2004					Three Months Ended March 31, 2003
	Income		Weighted Average Shares	Per Share		Loss			Weighted Average Shares		Per Share
Basic:
Net income (loss) attributable to common stock	$	1,180,337	11,145,896	$	0.11	$	(1,912,365	)	9,158,755		$	(0.21	)

Effect of Dilutive Securities:
Stock options and warrants		—	1,138,862					(a)		(a)
Series A preferred stock		17,777	362,637					(a)		(a)
Series B preferred stock		35,556	412,088					(a)		(a)
Series C preferred stock		120,000	1,333,328				—		—

Diluted:
Net income (loss)	$	1,353,670	14,392,811	$	0.09	$	(1,912,365	)	9,158,755		$	(0.21	)

(a)	Anti-dilutive.


	Nine Months Ended March 31, 2004					Nine Months Ended March 31, 2003
	Income		Weighted Average Shares	Per Share		Loss			Weighted Average Shares		Per Share
Basic:
Net income (loss) attributable to common stock	$	8,200,570	9,927,796	$	0.83	$	(6,139,817	)	9,080,392		$	(0.68	)

Effect of Dilutive Securities:
Stock options and warrants		—	882,287					(a)		(a)
Series A preferred stock		117,777	789,091					(a)		(a)
Series B preferred stock		235,556	896,695					(a)		(a)
Series C preferred stock		146,667	533,331				—		—

Diluted:
Net income (loss)	$	8,700,570	13,029,200	$	0.67	$	(6,139,817	)	9,080,392		$	(0.68	)

(a)	Anti-dilutive.

6. Commodity Price Hedges

Contango in the past entered into commodity derivative contracts. These contracts, which were usually placed with large energy pipeline and trading companies, major petroleum companies or financial institutions that the Company believed were minimal credit risks, took the form of futures contracts, swaps or options. In June 1998, the FASB issued SFAS 133. In June 2000, the FASB issued SFAS 138, “Accounting for Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133”. SFAS 133, as amended, established accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

value. The statement requires that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge criteria are met. The Company recognized changes in derivatives’ fair value in its income statement under gain (loss) from hedging activities. The derivative contracts called for the Company to receive, or make, payments based upon the differential between a fixed and a variable commodity price as specified in the contract.

The Company had no open commodity derivative contracts at March 31, 2004.

Due to the significant volatility in natural gas prices and the potential risk of significant hedging losses if NYMEX natural gas prices spike on the date options settle, the Company’s current policy is to hedge only through the purchase of puts.

7. Gain on Sale of Marketable Securities

As part of the formation of Freeport LNG Development, L.P., Cheniere Energy, Inc. (“Cheniere”) granted Contango warrants to purchase 300,000 shares of Cheniere common stock. In June and September 2003, Contango exercised the warrants, purchasing 300,000 shares of Cheniere common stock. As of March 31, 2004, the Company had sold 300,000 shares of Cheniere common stock and reported a gain on the sale of marketable securities for the nine months ended March 31, 2004 of $710,322.

8. Series C Convertible Preferred Stock

On December 12, 2003, Contango sold 1,600 shares of its Series C convertible cumulative preferred stock (the “Series C Preferred Stock”) to a group of private institutional investors for gross proceeds of $8.0 million. Series C Preferred Stock ranks prior to the Company’s common stock (and any other junior stock) with respect to the payment of dividends or distributions and upon liquidation, dissolution, winding-up or otherwise and is junior to the Company’s Series A senior convertible cumulative preferred stock and Series B senior convertible cumulative preferred stock. Holders of Series C Preferred Stock are entitled to receive quarterly dividends at a dividend rate equal to 6% per annum if paid in cash on a current quarterly basis or otherwise at a rate of 7.5% per annum if not paid on a current quarterly basis or if paid in shares of Series C Preferred Stock, in each case, computed on the basis of $5,000 per share. Holders of Series C Preferred Stock may, at their discretion, elect to convert such shares to shares of the Company’s common stock at a conversion price of $6.00 per share. After June 12, 2005, upon the occurrence of certain events, the Company may elect to convert all of the outstanding shares of Series C Preferred Stock into Contango common stock. The Company has filed a shelf registration with the Securities and Exchange Commission, which is effective, covering the 1,333,328 common shares issuable upon conversion of the Series C preferred stock.

9. Conversion of Series A and Series B Preferred Stock into Common Stock

On February 2, 2004, the Company converted its Series A convertible cumulative preferred stock (the “Series A Preferred Stock”) and its Series B convertible cumulative preferred stock (the “Series B Preferred Stock”) to shares of common stock. The Series A Preferred Stock had a face value of $2.5 million, paid an 8.0% annual dividend and was converted into 1,000,000 shares of Contango common stock. The Series B Preferred Stock had a face value of $5.0 million, paid an 8.0% annual dividend and was converted into 1,136,364 shares of Contango common stock. The Company has filed a shelf registration with the Securities and Exchange Commission, which is effective, covering these 2,136,364

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

shares of common stock, plus an additional 1,851,852 shares of common stock owned by the holder of the Series A Preferred Stock. As a result of the conversion of the Series A Preferred Stock and Series B Preferred Stock, together with the exercise of certain warrants and stock options, the number of the Company’s outstanding shares of common stock totaled 12,110,700 as of March 31, 2004.

10. Sale of Properties

In September 2003, the Company completed the sale of certain reserves in Brooks County, Texas for $5.0 million and recorded a gain of $982,000 for the nine months ended of March 31, 2004. Proved reserves were 1.5 Bcfe and accounted for approximately $5.0 million of the Company’s discounted present value at 10% per annum as of June 30, 2003.

In December 2003, Contango and Republic Exploration sold their producing Gulf of Mexico leases for approximately $12.0 million. As a result of this sale, Contango recorded a gain of approximately $6.2 million as of March 31, 2004. Properties included in the sale were Eugene Island 110, Grand Isle 28 and High Island 25-L. Contango received approximately $3.7 million in cash proceeds for its portion of the sale. Republic Exploration received cash proceeds of approximately $8.3 million for its portion of the sale. Republic Exploration subsequently made distributions of $3.0 million to its members, including a $1.0 million distribution to Contango.

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-KSB for the fiscal year ended June 30, 2003, previously filed with the Securities and Exchange Commission.

Uncertainty of Forward-Looking Statements and Information

Some of the statements made in this Form 10-Q 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 and budgets

•

Anticipated capital expenditures

•

Drilling of wells

•

Natural gas and oil reserves

•

Timing and amount of future production of natural gas and oil

•

Operating costs and other expenses

•

Cash flow and anticipated liquidity

•

Prospect development

•

Property acquisitions and sales

•

Hedging results

•

Development of our LNG receiving terminal

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:

•

The risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry holes

•

Availability of capital and the ability to repay indebtedness when due

•

Ability to raise capital to fund capital expenditures

•

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

•

Natural gas and oil price 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 or pipeline mishaps

•

Climatic conditions

•

Availability and cost of material and equipment

•

Delays in anticipated start-up dates

•

Actions or inactions of third-party operators of our properties

•

Commodity price movements adversely affecting our hedge position

•

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

•

Operational and financial risks associated with foreign exploration and production

You should not unduly rely on these forward-looking statements in this Form 10-Q, as they speak only as of the date of this Form 10-Q. 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 Form 10-Q or to reflect the occurrence of unanticipated events. See the information under the heading “Risk Factors” in our Form 10-KSB for the fiscal year ended June 30, 2003 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

We are an independent natural gas and oil company engaged in the exploration, production and acquisition of natural gas and oil in the United States. Our south Texas properties currently account for all of our production. We also own leases and conduct exploration activities offshore in the Gulf of Mexico and hold a 10% limited partnership interest in a proposed LNG terminal in Freeport, Texas.

Our Strategy

Our 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 developed by our alliance partners. Because we only have four employees, we depend on alliance partners for exploration, development and production expertise. Our four alliance partners, Juneau Exploration, L.P. (“JEX”), Alta Resources, LLC, Coastline Exploration, Inc. and Ameritex Minerals and Exploration, Ltd., perform all of our prospect generation and evaluation functions.

Negotiated acquisitions of proved properties. We continue to seek negotiated producing property acquisitions based on our view of the pricing cycles of natural gas and oil and available exploitation opportunities of probable and possible reserves. Since January 1, 2002, we have acquired approximately 14.0 Bcfe of proved developed producing reserves of natural gas and oil.

Sale of proved properties. From time-to-time as part of our business strategy, we may sell some or a substantial portion of our proved reserves to capture current value, using the sales proceeds to further our exploration activities. In July 2003, we sold producing properties consisting of 10 wells in south Texas for $5.0 million, and in December 2003, Contango and its 33%-owned subsidiary, Republic Exploration LLC, sold all of their then producing Gulf of Mexico leases for approximately $12.0 million.

Controlling general and administrative and geological and geophysical costs. Our goal is to be among the highest in the industry in revenue and profit per employee and among the lowest in general and administrative costs. We plan to continue outsourcing our geological, geophysical, reservoir engineering and land functions, and partnering with cost efficient operators whenever possible. We have four employees.

Structuring transactions to minimize front-end investments. We seek to maximize returns on capital by minimizing our up-front investments in acreage, seismic data and prospect generation whenever possible. We want our partners to share in both the risk and the rewards of our success.

Seeking new alliance ventures. While our core focus will remain the domestic exploration and production business, we will also continue to seek opportunities that may include foreign exploration prospects, such as our recent agreement with Texas Petroleum Investment Company (“TPIC”) to drill an exploratory oil well in the Aquitaine Basin in southwestern France. We may also make investments in joint ventures and assets related to the energy business.

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 approximately 21% of our common stock. In addition, our alliance partners co-invest in prospects that they recommend to us.

Exploration Alliances with JEX, Alta Resources and Coastline

Alliance with JEX. Under our agreement with JEX, JEX evaluates natural gas and oil prospects and recommends exploration prospect and proved property acquisition investment opportunities to us. In exchange, we have committed, within various parameters, to invest along with JEX up to 95% of the available working interest in the recommended prospects and property acquisitions. Under the JEX agreement, JEX brings onshore prospects directly to Contango. Offshore prospects are typically generated by our partially owned subsidiaries, Republic Exploration LLC, Magnolia Offshore Exploration LLC and Contango Offshore Exploration LLC. See “Offshore Exploration Joint Ventures” below.

If JEX recommends any prospects to Contango, we pay the lease and seismic costs, and JEX generally pays the remaining costs of generating and preparing a prospect to drill ready status. When drilling begins on a prospect, we are obligated to assign to the JEX geoscientists an overriding royalty interest equal to 3¹/3% of our working interest in the prospect. In addition, when our revenues from prospects we invest in under the agreement during a calendar year, net of taxes, royalties and other expenses equals our capital expenditure related to the acquisition and development of the prospects on a well-by-well basis, JEX is entitled to an assignment or automatic reversion of 25% of our working interest in the well. With respect to reserve acquisitions, we have the right, but not the obligation, to purchase up to 95% of the interests available to JEX in proved natural gas and oil reserves.

We may terminate the agreement upon 30 days written notice, and JEX may terminate the agreement upon 180 days notice. If we are in default under the agreement, however, JEX may terminate the agreement upon 30 days written notice.

Alliance with Alta Resources. Alta Resources is a private company formed for the purpose of assembling domestic, onshore natural gas and oil prospects. In July 2003, Contango and Alta Resources entered into an agreement with Seitel Data Ltd. for a 3-D seismic shoot covering approximately 40 square miles in southern Duval County, Texas. The cost to Contango for this 3-D seismic shoot was approximately $1.7 million. The seismic shoot was completed in November 2003, and processing, evaluation and prospect identification is continuing.

Alliance with Coastline. Coastline is a private company engaged in domestic, onshore natural gas and oil exploration and production. In October 2003, Contango and Coastline entered into an exploration agreement to explore and develop prospects in south Texas. Our investment in this exploration venture currently totals $75,000.

Alliance with Ameritex. In February 2004, we entered into an exploration agreement with Ameritex, a privately held San Antonio based prospect generation and exploration company, founded in 1982. Our participation percentage is 33.3%, with Ameritex being carried 25% to casing point. Ameritex’s activities are concentrated on the generation of exploration opportunities utilizing 3-D seismic technology. The annual G&G cost to Contango for this prospect generation effort is approximately $80,000 per year.

Domestic Onshore Exploration and Properties

JEX Activities

In 2003, we participated in a 3-D seismic shoot in Jim Hogg and Starr Counties, Texas, covering approximately 100 square miles at a net cost to us of approximately $2.3 million. Between September 2003 and March 2004, we drilled eight wells, six shallow and two deep, resulting in three shallow successes. The overall results of this exploration play have been disappointing. Total costs have approximated $5.4 million, with estimated value of discovered reserves of approximately $1.3 million. No further drilling is planned for this area.

In August 2003, Contango, along with JEX, entered into a participation agreement with several other parties to identify and evaluate natural gas and oil exploration prospects in a prospect area covering approximately 32,000 acres in Dimmit and Zavala Counties, Texas. Our share of prospect identification is expected to cost approximately $1.0 million. We currently have advanced approximately $393,000 as our share of prospect identification costs. No drillable prospects have been identified to date.

We recently participated with an approximate 7.1% working interest in a 15,500-foot Wilcox test in Goliad County, Texas. Our cost to drill and complete this well was approximately $454,000. The well has been deemed unsuccessful.

Alta Resources Activities

In October 2003, Contango and Alta Resources completed a 3-D seismic shoot covering approximately 40 square miles in southern Duval County, Texas. The net cost to us was approximately $1.7 million. A Queen City prospect has been drilled and is being completed. An offset Queen City

location is currently drilling. Our estimated dry hole cost of this second well is approximately $476,000. An additional two shallow prospects have been identified. Evaluation of the available seismic data and prospect identification is continuing.

We have recently agreed to participate with Alta Resources in an exploratory Frio well located onshore in Matagorda County, Texas. The dry hole cost is estimated at approximately $1.4 million, of which our share will be approximately $700,000. After casing point, we will own an approximate 34% working interest in the well. Drilling is expected to commence in the June 2004 timeframe.

Coastline Activities

In October 2003, we agreed to participate with Coastline in any exploration prospects that may be generated in a prospect area in Kenedy County, Texas using existing 3-D seismic data. No drillable prospects were identified using this data. Coastline is continuing its prospect generation.

Ameritex Activities

In February 2004, we entered into an exploration agreement with Ameritex. Ameritex has currently identified five prospect areas. We are currently drilling an 11,400 foot Wilcox test in Zapata County, Texas. We have a 25.8% working interest before casing point (19.4% after casing point). Our estimated dry hole cost is approximately $420,000. Prospect generation is continuing on five identified prospect areas.

International Onshore Exploration and Properties

Contango and TPIC have agreed to pursue an oil exploration prospect in the Aquitaine Basin in southwestern France. The initial well will be an oil test to be drilled to approximately 10,500 feet. The dry hole cost of this well is estimated at approximately $4.0 million, with Contango’s 20% dry hole exposure estimated at approximately $800,000. Drilling is expected to commence May 2004. We will develop our future plans in France based on the results of this well.

Offshore Gulf of Mexico Exploration Joint Ventures

Contango. Contango directly and through affiliated companies conducts exploration activities in the Gulf of Mexico. Currently, Contango has a direct interest in three offshore leases. See “Offshore Operations and Properties” below for additional information on Contango’s offshore properties.

Contango also owns an equity interest in Republic Exploration, Magnolia Offshore Exploration and Contango Offshore Exploration, formed for the purpose of generating exploration opportunities in the Gulf of Mexico. These companies have collectively licensed approximately 4,000 blocks of 3-D seismic data and have focused on identifying prospects, acquiring leases at federal and state lease sales and then selling the prospects to third parties, subject to timed drilling obligations plus retained reversionary interests in favor of the LLCs. In the future, Contango may choose to take a direct working interest in some of these prospects under the same arms-length terms available to industry partners.

Republic Exploration LLC. Contango’s original investment in Republic Exploration in August 2000 was approximately $6.7 million for a 33.3% ownership interest. The other members of Republic Exploration are JEX, its managing member, and a privately held seismic company. Both have comprehensive offshore experience. Republic Exploration holds a non-exclusive license to approximately

1,700 blocks of 3-D seismic data in the shallow waters of the Gulf of Mexico. This data is used to identify, acquire and exploit natural gas and oil prospects. All leases owned by Republic Exploration are subject to a 3.3% overriding royalty interest in favor of the JEX exploration team. See “Offshore Operations and Properties” below for more information on Republic Exploration’s offshore properties.

Magnolia Offshore Exploration LLC. Contango purchased a 50% interest in Magnolia Offshore Exploration in October 2001. JEX is the only other member and acts as the managing member. In March 2002, Magnolia Offshore Exploration was the high bidder on three blocks offshore Louisiana in the Gulf of Mexico lease sale. In November 2002, the members of Magnolia Offshore Exploration made the decision to limit activities to its three existing leases; thus, no additional leases will be acquired. One lease block was drilled, resulting in a dry hole, and the other two lease blocks are available for farmout. Contango’s current investment in Magnolia Offshore Exploration is approximately $763,000. See “Offshore Operations and Properties” below for additional information on Magnolia Offshore Exploration’s properties.

Contango Offshore Exploration LLC. Contango purchased a 66.7% interest in Contango Offshore Exploration in September 2002. JEX is the only other member and acts as the managing member. Contango Offshore Exploration’s activities will be focused on identifying and purchasing prospects in the Gulf of Mexico and selling them to third parties, retaining a reversionary interest. Contango Offshore Exploration has invested approximately $11.7 million to acquire and reprocess 2,294 blocks of 3-D seismic data and to acquire leases in the Gulf of Mexico. Contango Offshore Exploration has acquired a total of eight leases, all of which are available for farmout. All leases will be subject to a 3.3% overriding royalty interest in favor of the JEX exploration team. See “Offshore Operations and Properties” below for additional information on Contango Offshore Exploration’s properties.

Current Activities. On March 17, 2004, Republic Exploration and Contango Offshore Exploration bid on 37 blocks and were the apparent high bidders on 24 blocks offered at the Central Gulf of Mexico Lease Sale #190 held in New Orleans. Each of these blocks is located on the shelf of the Gulf of Mexico in water depths of less than 200 meters. An apparent high bid (“AHB”) gives the bidding party propriety 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. As of May 12, 2004, the MMS had awarded 18 blocks of the 24 AHB blocks. In addition, Republic Exploration and Contango Offshore Exploration will share a reversionary carried working interest in Vermilion 154, which was an AHB at Lease Sale #190. If these blocks are awarded, Contango will own interests, both directly and indirectly through its affiliates, in 41 federal lease blocks in the Gulf of Mexico, covering approximately 202,200 acres.

Contango and Republic Exploration recently farmed out two lease blocks, Vermilion 73 and Eugene Island 113B. A deep test on Vermilion 73 was unsuccessful. A shallower well on Vermilion 73 expected to be drilled during the summer of 2004. Eugene Island 113B is expected to spud in June 2004.

The Minerals Management Service (“MMS”) has implemented a rule on royalty relief for shallow water, deep 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 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 well depths greater than 18,000 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.

Offshore Properties

The following table sets forth the interests owned by Contango and related entities in the Gulf of Mexico as of May 12, 2004:


Area/Block	WI		NRI		Acquired	Status
Contango Oil & Gas Company:
Brazos 436	13.6	%	10.8	%	Jul-00	Shut in; sale pending
East Cameron 107	33.8	%	27.0	%	May-01	Available for farm-out
Eugene Island 113B		(2)		(2)	May-01	Farmed-out; drilling expected in 2004

Area/Block	WI		NRI		Acquired	Status
Republic Exploration (1):
East Cameron 107	66.2	%	53.0	%	May-01	Available for farm-out
Eugene Island 113B		(2)		(2)	May-01	Farmed-out; additional drilling expected in 2004
West Delta 36	100.0	%	80.0	%	May-02	Available for farm-out
Vermilion 73		(3)		(3)	Jul-02	Farmed-out; drilling expected in 2004
West Cameron 174	100.0	%	80.0	%	Jun-03	Available for farm-out
High Island 113	100.0	%	80.0	%	Sep-03	Available for farm-out
South Timbalier 191	50.0	%	40.0	%	May-04	Available for farm-out
Vermilion 36	100.0	%	80.0	%	May-04	Available for farm-out
Vermilion 109	100.0	%	80.0	%	May-04	Available for farm-out
Vermilion 134	100.0	%	80.0	%	May-04	Available for farm-out
West Cameron 179	100.0	%	80.0	%	May-04	Available for farm-out
West Cameron 185	100.0	%	80.0	%	May-04	Available for farm-out
West Cameron 200	100.0	%	80.0	%	May-04	Available for farm-out
West Delta 18	100.0	%	80.0	%	May-04	Available for farm-out
West Delta 33	100.0	%	80.0	%	May-04	Available for farm-out
West Delta 34	100.0	%	80.0	%	May-04	Available for farm-out
West Delta 43	100.0	%	80.0	%	May-04	Available for farm-out
Ship Shoal 220	50.0	%	40.0	%	May-04	Available for farm-out
South Timbalier 240	50.0	%	40.0	%	May-04	Available for farm-out
Eugene Island 76	100.0	%	80.0	%	Pending	Apparent high bid
South Marsh 247	100.0	%	80.0	%	Pending	Apparent high bid
Vermilion 130	100.0	%	80.0	%	Pending	Apparent high bid
West Cameron 80	100.0	%	80.0	%	Pending	Apparent high bid
West Cameron 133	100.0	%	80.0	%	May-04	Available for farm-out
West Cameron 167	100.0	%	80.0	%	Pending	Apparent high bid

Area/Block	WI		NRI		Acquired	Status
Magnolia Offshore Exploration (1):
Ship Shoal 155	100.0	%	80.0	%	May-02	Available for farm-out
Viosca Knoll 75	100.0	%	80.0	%	May-02	Available for farm-out

Area/Block	WI		NRI		Acquired	Status
Contango Offshore Exploration (1):
Vermilion 231	100.0	%	80.0	%	May-03	Available for farm-out
Viosoca Knoll	100.0	%	80.0	%	May-03	Available for farm-out
Eugene Island 209	100.0	%	80.0	%	Jun-03	Available for farm-out
Viosca Knoll 161	100.0	%	80.0	%	Jun-03	Available for farm-out
High Island A16	100.0	%	80.0	%	Nov-03	Available for farm-out
East Breaks 283	100.0	%	80.0	%	Nov-03	Available for farm-out


Area/Block	WI		NRI		Acquired	Status
Contango Offshore Exploration - conti. (1):
East Breaks 369	100.0	%	80.0	%	Nov-03	Available for farm-out
East Breaks 370	100.0	%	80.0	%	Nov-03	Available for farm-out
South Timbalier 191	50.0	%	40.0	%	May-04	Available for farm-out
Grand Isle 63	100.0	%	80.0	%	Jun-04	Available for farm-out
Grand Isle 72	100.0	%	80.0	%	Jun-04	Available for farm-out
Grand Isle 73	100.0	%	80.0	%	Jun-04	Available for farm-out
Ship Shoal 220	50.0	%	40.0	%	May-04	Available for farm-out
South Timbalier 240	50.0	%	40.0	%	May-04	Available for farm-out
Main Pass 221	100.0	%	80.0	%	Pending	Apparent high bid
Viosca Knoll 118	100.0	%	80.0	%	May-04	Available for farm-out

(1)	Contango has a 33.3% interest in Republic Exploration, 50% interest in Magnolia Offshore Exploration (subject to a third party net profits interest) and 66.7% interest in Contango Offshore Exploration.

(2)	Contango (33.75%) and Republic Exploration (66.25%) will collectively have a 5.0% overriding royalty interest (1.7% and 3.3%, respectively).

(3)

At project payout, Republic Exploration will have the option to elect to receive a 25% working interest (20% net revenue interest) or a 10% ORRI; provided, however, Republic’s interest (after payout) in any wells drilled within the participating area, covering depth limited-portions of this block and three other contiguous third party-owned blocks, will either be a 4.625% WI (3.70% NRI) or a 1.85% ORRI (inasmuch as VR-73 comprises only 18.5% of the lands included in the four block participating area).

Freeport LNG Development, L.P.

In March 2003, we exercised an option to purchase from Cheniere Energy, Inc. a 10% limited partnership interest in Freeport LNG Development, L.P. (“Freeport LNG Project” and “Freeport LNG”), a limited partnership formed to develop a LNG receiving terminal in Freeport, Texas. Our commitment is $2.3 million, $1,850,000 of which has been paid as of April 15, 2004. The balance of $483,333 consists of a final payment of $83,333 due on May 15, 2004 and a payment of $400,000 due upon receipt of Federal Energy Regulatory Commission (“FERC”) approval for the project.

In March 2003, Freeport LNG submitted a filing to FERC for the construction of the LNG receiving terminal. In August 2003, Freeport LNG signed a contract with Technip USA, a subsidiary of Technip, for the Front End Engineering Design that will lead to the finalization of the engineering, procurement and construction contract for its proposed LNG receiving terminal.

In November 2003, FERC concluded in a draft Environmental Impact Statement (“EIS”) that the approval of Freeport LNG’s proposed liquefied natural gas receiving terminal, with the adoption of recommended mitigation measures, would have limited adverse environmental impact and would be an environmentally acceptable action. Freeport LNG expects to receive a final EIS and final FERC approval for its application to build a 1.5 Bcf per day LNG receiving terminal near Freeport, Texas in 2004. The EIS provided for a comment period, and FERC has conducted a public meeting that gave interested parties an opportunity to comment on the draft EIS. Assuming that FERC approval is received in the spring of 2004, the construction phase is expected to commence during the summer of 2004, with the first LNG shipment being received in the second half of 2007.

In December 2003, ConocoPhillips and Freeport LNG signed an agreement providing for ConocoPhillips’ participation in Freeport LNG’s project to build the receiving terminal. ConocoPhillips will acquire one billion cubic feet per day of capacity in the terminal for its use, obtain a 50% interest in the general partner of Freeport LNG, and provide construction funding presently estimated in excess of $500 million. We continue to own a 10% limited partnership interest in the project.

The management of Freeport LNG will remain in place and be responsible for all commercial activities and customer interface for the remaining capacity in the facility. ConocoPhillips will be primarily responsible for the management of construction and operation of the facility. The transaction calls for ConocoPhillips, as a user of the facility, to pay its proportionate share of operating expenses and fuel costs, a throughput fee of $0.05 per Mcf, and all amounts necessary to amortize the construction funding. In addition, ConocoPhillips has paid a non-refundable capacity reservation fee of $10.0 million to Freeport LNG. The transaction is expected to close in the spring of 2004, subject to completion of remaining documentation and satisfaction of closing conditions.

In February 2004, Freeport LNG signed a 20-year terminal use agreement with The Dow Chemical Company for up to 500 MMcf per day of throughput capacity at Freeport LNG’s receiving terminal. Under the terms of the agreement, Dow has made a firm commitment to reserve throughput capacity for 250 MMcf per day and has until August 31, 2004 to exercise an option on the remaining 250 MMcf per day.

As part of the formation of Freeport LNG Development, L.P., Cheniere granted Contango warrants to purchase 300,000 shares of Cheniere common stock. In June and September 2003, Contango exercised the warrants, acquiring 300,000 shares of Cheniere common stock. As of March 31, 2004, we had sold the 300,000 shares, recognizing a gain of $710,322 for the nine months ended March 31, 2004. See MD&A, “Gain on Sale of Marketable Securities” for additional information.

Critical Accounting Policies

The primary objectives of FIN 46R are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights (these entities are referred to as “variable interest entities” or “VIEs”) and how to determine if a business enterprise should consolidate the VIEs. This new model for consolidation applies to an entity for which either:

•

the equity investors (if any) do not have a controlling financial interest; or

•

the equity investment at risk is insufficient to finance the entity’s activities without receiving additional subordinated financial support from other parties.

In addition, FIN 46R requires that all enterprises with a significant variable interest in a VIE make additional disclosures regarding their relationship with the VIE. The interpretation requires public entities to apply FIN 46R to all entities that are considered SPEs in practice and under the FASB literature that was applied before the issuance of FIN 46R by the end of the first reporting period that ends after December 15, 2003. Application of the accounting requirements of the interpretation to all other entities is required by the end of the first reporting period that ends after March 15, 2004. The adoption of FIN 46R had no effect on the Company’s financial statements.

In June 1998, the FASB issued SFAS 133, “Accounting for Derivative Instruments and Hedging Activities”. SFAS 133 established accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts), as defined, be recorded in the balance sheet as either an asset or liability measured at fair value and requires that changes in fair value were recognized in earnings unless specific hedge accounting criteria are met.

The table below sets forth the Company’s hedging activities for the periods indicated:


	Three Months Ended									YTD Total March 31, 2004
	September 30, 2003			December 31, 2003			March 31, 2004			YTD Total March 31, 2004
Mark-to-market reversal of prior period unrealized recognized (gain) loss	$	58,171		$	(24,071	)	$	—		$	58,171
Mark-to-market gain unrealized		24,071			—			—			—

Gain (loss) from hedging activities	$	82,242		$	(24,071	)	$	—		$	58,171


	Three Months Ended									YTD Total March 31, 2003
	September 30, 2002			December 31, 2002			March 31, 2003			YTD Total March 31, 2003
Mark-to-market reversal of prior period unrealized recognized loss (gain)	$	125,674		$	228,615		$	(759,887	)	$	125,674
Net cash received (paid) from swap settlements/options purchased		109,585			(1,181,472	)		(4,433,403	)		(5,505,290	)
Mark-to-market gain (loss) unrealized		(228,615	)		759,887			(37,382	)		(37,382	)

Gain (loss) from hedging activities	$	6,644		$	(192,970	)	$	(5,230,672	)	$	(5,416,998	)

Although the Company’s hedging transactions generally are designed as economic hedges for a portion of future natural gas and oil production, the Company has elected not to designate the derivative instruments as “hedges” under SFAS 133. As a result, gains and losses, representing changes in these derivative instruments’ mark-to-market fair values, ere recognized in the Company’s earnings (see footnote 6 for more information on hedging activities).

The Company had no open commodity derivative contracts at March 31, 2004.

MD&A Summary Data

The table below sets forth, for the periods indicated, summary information discussed below.


	Three Months Ended March 31,							Nine Months Ended March 31,
	2004		2003			Change		2004		2003			Change
Natural gas and oil sales	$	6,611,139	$	10,061,351		-34	%	$	20,843,951	$	24,793,109		-16	%
Gain (loss) from hedging activities	$	—	$	(5,230,672	)		*	$	58,171	$	(5,416,998	)		*

Production:
Natural gas (thousand cubic feet per day)		11,061		14,693		-25	%		12,418		16,943		-27	%
Oil and condensate (barrels per day)		221		342		-35	%		283		392		-28	%

Average sales price:
Natural gas (per thousand cubic feet)	$	5.90	$	6.84		-14	%	$	5.41	$	4.69		15	%
Oil and condensate (per barrel)	$	33.44	$	33.22		1	%	$	30.57	$	27.96		9	%

Operating expenses	$	493,008	$	1,448,367		-66	%	$	3,061,922	$	4,179,166		-27	%
Exploration expenses	$	1,737,499	$	3,588,654		-52	%	$	5,225,497	$	15,496,798		-66	%
Depreciation, depletion and amortization	$	1,747,527	$	1,942,144		-10	%	$	5,160,262	$	6,518,654		-21	%
Impairment of natural gas and oil properties	$	—	$	—				$	42,995	$	—			*
General and administrative expenses	$	662,898	$	391,483		69	%	$	1,808,478	$	1,464,576		23	%
Interest expense	$	28,804	$	177,860		-84	%	$	308,449	$	531,763		-42	%
Interest income	$	12,263	$	6,498		89	%	$	31,929	$	27,663		15	%
Gain on sale of marketable securities	$	—	$	—			*	$	710,322	$	—			*
Gain on sale of assets and other	$	128,904	$	—			*	$	7,245,314	$	36,150			*

*	Not meaningful

Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003

Natural Gas and Oil Sales. We reported natural gas and oil sales of approximately $6.6 million for the three months ended March 31, 2004, down from approximately $10.1 million reported for the three months ended March 31, 2003. This decrease was attributable to normal production declines in existing fields, the sale of reserves in Brooks County, Texas effective July 1, 2003 and to lower prices for our gas production.

Natural Gas and Oil Production and Average Sales Prices. Our net natural gas production for the three months ended March 31, 2004 was approximately 11.1 million cubic feet of natural gas per day, down from approximately 14.7 million cubic feet of natural gas per day for the three months ended March 31, 2003. Net oil production for the comparable periods decreased from 342 barrels of oil per day to 221 barrels of oil per day. This decrease was due to the natural decline in production from our south Texas properties and the sale of non-core reserves in Brooks County, Texas effective July 1, 2003. For the three months ended March 31, 2004, prices for natural gas and oil were $5.90 per Mcf and $33.44 per barrel, compared to $6.84 per Mcf and $33.22 per barrel for the three months ended March 31, 2003.

Loss from Hedging Activities. We reported a loss from hedging activities for the three months ended March 31, 2003 of approximately $5.2 million. This loss included an approximate $4.4 million realized loss consisting of an approximate $300,000 related to February 2003 calls and swaps, $2.7 million related to March 2003 calls and swaps, and $1.4 million related to April-October 2003 calls and swaps.

Operating Expenses. Operating expenses, including severance taxes, for the three months ended March 31, 2004 were approximately $0.5 million, down from the $1.4 million reported for the three months ended March 31, 2003. Of the $0.5 million reported for the three months ended March 31, 2004, approximately $16,000 was attributable to production and severance taxes. Operating expenses, including severance taxes, for the three months ended March 31, 2003 were approximately $1.4 million. Of the $1.4 million reported for the three months ended March 31, 2003, approximately $0.7 million was attributable to lease operating expense and ad valorem taxes, and approximately $0.7 million was attributable to production and severance taxes. The Railroad Commission of Texas has extended the natural gas incentive allowing for severance tax reduction on tight sand gas wells. As a result, some of our south Texas Queen City formation properties are now eligible for severance tax reduction. The decrease in operating expenses for the three months ended March 31, 2004 was attributable to lower severance taxes, including historic adjustments, as a result of severance tax reductions and to lower overall costs of operations resulting from lower production. You should not expect comparable low levels of production and severance taxes in future reporting periods.

Exploration Expense. We reported approximately $1.7 million of exploration expenses for the three months ended March 31, 2004. Of this amount, approximately $0.5 million was attributable to the cost to acquire and reprocess 3-D seismic data offshore in the Gulf of Mexico, approximately $0.3 million was the cost to shoot 3-D seismic in south Texas and $0.9 million was related to unsuccessful wells drilled in south Texas during the period. We reported approximately $3.6 million of exploration expenses for the three months ended March 31, 2003. Of this amount, approximately $2.8 million was attributable to the cost to acquire and reprocess 3-D seismic data offshore in the Gulf of Mexico, approximately $0.6 million was the cost to shoot 3-D seismic in south Texas and $0.2 million was related to dry holes drilled in south Texas.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months ended March 31, 2004 was approximately $1.7 million. For the three months ended March 31, 2003, we recorded approximately $1.9 million of depreciation, depletion and amortization. The decrease in depreciation, depletion and amortization was primarily the result of lower production from our south Texas properties.

General and Administrative Expenses. General and administrative expenses for the three months ended March 31, 2004 were approximately $0.7 million, up from $0.4 million for the three months ended March 31, 2003. Major components of general and administrative expenses for the three months ended March 31, 2004 included approximately $270,000 in salaries and benefits (including $125,000 of bonus accrual), $178,000 in legal, accounting, engineering and other professional fees, $95,000 of office administration expenses, $68,000 of insurance costs and $52,000 related to the cost of expensing stock options.

Interest Expense. We reported interest expense of approximately $29,000 for the three months ended March 31, 2004, down from the approximate $0.2 million reported for the three months ended March 31, 2003. This decrease primarily was attributable to lower average levels of borrowings under our bank line of credit.

Gain on Sale of Assets and Other. We reported a gain on sale of assets of approximately $0.1 million for the three months ended March 31, 2004, representing a purchase price adjustment on properties we sold within our south Texas exploration program effective July 1, 2003.

Nine Months Ended March 31, 2004 Compared to Nine Months Ended March 31, 2003

Natural Gas and Oil Sales. We reported natural gas and oil sales of approximately $20.8 million for the nine months ended March 31, 2004, compared to approximately $24.8 million reported for the nine months ended March 31, 2003. This decrease was attributable to normal production declines in existing fields and the sale of reserves in Brooks County, Texas effective July 1, 2003. These declines were partially offset by higher prices for natural gas and oil.

Natural Gas and Oil Production and Average Sales Prices. Our net natural gas production for the nine months ended March 31, 2004 was approximately 12.4 million cubic feet of natural gas per day, down from approximately 16.9 million cubic feet of natural gas per day for the nine months ended March 31, 2003. Net oil production for the comparable periods decreased from 392 barrels of oil per day to 283 barrels of oil per day. This decrease was due to the natural decline in production from our south Texas properties and the sale of reserves in Brooks County, Texas effective July 1, 2003. For the nine months ended March 31, 2004, prices for natural gas and oil were $5.41 per Mcf and $30.57 per barrel, up from $4.69 per Mcf and $27.96 per barrel for the nine months ended March 31, 2003.

Gain (loss) from Hedging Activities. We reported a gain from hedging activities for the nine months ended March 31, 2004 of approximately $58,000.

We reported a loss from hedging activities for the nine months ended March 31, 2003 of approximately $5.4 million. This loss included an approximate $5.4 million realized loss consisting of an approximate $300,000 related to February 2003 calls and swaps, $2.7 million related to March 2003 calls and swaps, $1.4 million related to April-October 2003 calls and swaps, and a $1.0 million cost realized on the purchase of calendar 2003 puts.

Operating Expenses. Operating expenses, including severance taxes, for the nine months ended March 31, 2004 were approximately $3.1 million, down from the $4.2 million reported for the nine months ended March 31, 2003. Of the $3.1 million reported for the nine months ended March 31, 2004, approximately $2.2 million was attributable to lease operating expense and ad valorem taxes, approximately $0.9 million was attributable to production and severance taxes. The Railroad Commission of Texas has extended the natural gas incentive allowing for severance tax reduction on tight sand gas wells. As a result, some of our south Texas Queen City formation properties are now eligible for severance tax reduction.

Operating expenses, including severance taxes, for the nine months ended March 31, 2003 were approximately $4.2 million. Of the $4.2 million reported for the nine months ended March 31, 2003, approximately $2.4 million was attributable to lease operating expense and approximately $1.8 million was attributable to production and severance taxes. The decrease in operating expenses for the nine months ended March 31, 2004 was attributable to lower overall costs of operations resulting from lower production and lower severance taxes as a result of severance tax reductions.

Exploration Expense. We reported approximately $5.2 million of exploration expenses for the nine months ended March 31, 2004. Of this amount, approximately $1.6 million was attributable to the cost to acquire and reprocess 3-D seismic data offshore in the Gulf of Mexico, approximately $2.0 million was the cost to shoot 3-D seismic in south Texas and approximately $1.6 million was related to unsuccessful wells drilled in south Texas during the period. We reported approximately $15.5 million of exploration expenses for the nine months ended March 31, 2003. Of this amount, approximately $11.4 million was attributable to the cost to acquire and reprocess 3-D seismic data offshore in the Gulf of Mexico, approximately $3.6 million was the cost to shoot and to acquire 3-D seismic in south Texas and approximately $0.5 million was related to dry hole costs in south Texas.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the nine months ended March 31, 2004 was approximately $5.2 million. For the nine months ended March 31, 2003, we recorded approximately $6.5 million of depreciation, depletion and amortization. The decrease in depreciation, depletion and amortization was primarily the result of lower production.

General and Administrative Expenses. General and administrative expenses for the nine months ended March 31, 2004 were approximately $1.8 million, compared to approximately $1.5 million for the nine months ended March 31, 2003. Major components of general and administrative expenses for the nine months ended March 31, 2004 included approximately $742,000 in salaries and benefits (including $375,000 of bonus accrual), $285,000 in legal, accounting, engineering and other professional fees, $285,000 of office administration expenses, $181,000 of insurance costs, $129,000 related to the cost of expensing stock options and $187,000 of other expenses.

Interest Expense. We reported interest expense of approximately $0.3 million for the nine months ended March 31, 2004, down from the $0.5 million reported for the nine months ended March 31, 2003. This decrease primarily was attributable to lower average levels of borrowings under our bank line of credit.

Gain on Sale of Marketable Securities. As part of the formation of Freeport LNG Development, L.P., Cheniere granted Contango warrants to purchase 300,000 shares of Cheniere common stock. In June and September 2003, Contango exercised the warrants, purchasing 300,000 shares of Cheniere common stock. As of March 31, 2004, the Company had sold the 300,000 shares of Cheniere common stock. For the nine months ended March 31, 2004, we reported a gain on the sale of marketable securities of approximately $0.7 million (see footnote 7 to Notes to Consolidated Financial Statements).

Gain on Sale of Assets and Other. For the nine months ended March 31, 2004, we reported an approximate $7.2 million gain on the sale of assets.

In September 2003, we sold properties within our south Texas exploration program consisting of 10 wells in Brooks County, Texas for $5.0 million, reporting a gain of approximately $1.0 million attributable to this producing property sale.

In December 2003, Contango and its 33.3%-owned subsidiary, Republic Exploration, sold their producing Gulf of Mexico leases for approximately $12.0 million. As a result of this sale, Contango recorded a gain of approximately $6.2 million as of March 31, 2004. Properties included in the sale were Eugene Island 110, Grand Isle 28 and High Island 25-L. Because the interests sold were unearned back-in working interests, Contango had no proved reserves attributable to the properties sold (see footnote 10 to Notes to Consolidated Financial Statements).

Production, Prices, Operating Expenses, EBITDAX and Other

The following table presents information regarding the production volumes, average sales prices received and average production costs associated with our sales of natural gas and oil for the periods indicated. Oil and condensate are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil or condensate is the energy equivalent of six Mcf of natural gas.


	Three Months Ended March 31,				Nine Months Ended March 31,
	2004		2003		2004		2003
Natural gas and oil sales	$	6,611,139	$	10,061,351	$	20,843,951	$	24,793,109

Production:
Natural gas (thousand cubic feet)		1,006,576		1,322,400		3,414,932		4,642,314
Oil and condensate (barrels)		20,108		30,744		77,873		107,389
Total (thousand cubic feet equivalent)		1,127,224		1,506,864		3,882,170		5,286,648

Natural gas (thousand cubic feet per day)		11,061		14,693		12,418		16,943
Oil and condensate (barrels per day)		221		342		283		392
Total (thousand cubic feet equivalent per day)		12,387		16,745		14,116		19,295

Average sales price:
Natural gas (per thousand cubic feet)	$	5.90	$	6.84	$	5.41	$	4.69
Oil and condensate (per barrel)	$	33.44	$	33.22	$	30.57	$	27.96
Total (per thousand cubic feet equivalent)	$	5.86	$	6.67	$	5.37	$	4.69

Selected data per Mcfe:
Production and severance taxes	$	0.02	$	0.48	$	0.22	$	0.33
Lease operating expenses	$	0.42	$	0.48	$	0.57	$	0.46
General and administrative expenses	$	0.59	$	0.26	$	0.47	$	0.28
Depreciation, depletion and amortization of natural gas and oil properties	$	1.52	$	1.25	$	1.30	$	1.21

EBITDAX (1)	$	5,584,137	$	2,990,829	$	23,987,358	$	13,768,519

(1)

EBITDAX represents earnings before interest, income taxes, depreciation, depletion and amortization, impairment expenses, exploration expenses, including gain (loss) from hedging activities and sale of assets. We have reported EBITDAX because we believe EBITDAX is a measure commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. We believe EBITDAX assists investors in comparing a company’s performance on a consistent basis without regard to depreciation, depletion and amortization, impairment of natural gas and oil properties and exploration expenses, which can vary significantly depending upon accounting methods. EBITDAX is not a calculation based on U.S. generally accepted accounting principles and should not be considered an alternative to net income (loss) in measuring our performance or used as an exclusive measure of cash flow because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions and other sources and uses of cash, which are disclosed in our statements of cash flows. Investors should carefully consider the specific items included in our computation of EBITDAX. While we have disclosed our EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, investors should be cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service, preferred stock dividends and other commitments.

A reconciliation of EBITDAX to income (loss) from operations for the periods indicated is presented below.


	Three Months Ended March 31,					Nine Months Ended March 31,
	2004		2003			2004		2003
Income (loss) from operations	$	1,970,207	$	(2,539,969	)	$	5,602,968	$	(8,283,083	)
Exploration expenses		1,737,499		3,588,654			5,225,497		15,496,798
Depreciation, depletion and amortization		1,747,527		1,942,144			5,160,262		6,518,654
Impairment of natural gas and oil properties		—		—			42,995		—
Gain on sale of marketable securities		—		—			710,322		—
Gain on sale of assets and other		128,904		—			7,245,314		36,150

EBITDAX	$	5,584,137	$	2,990,829		$	23,987,358	$	13,768,519

Capital Resources and Liquidity

Cash Inflows

During the nine months ended March 31, 2004, we funded our activities with internally generated cash flow, bank borrowings, sales of assets and the sale of our Series C preferred stock. We reported total revenues for the three and nine months ended March 31, 2004 of approximately $6.6 million and $20.9 million, respectively. EBITDAX for the three and nine months ended March 31, 2004 was approximately $5.6 million and $24.0 million, respectively.

Our current production rate is approximately 13,000 MMbtue per day. At anticipated production levels and current commodity price levels, we expect to have EBITDAX of approximately $1.5 to $ 2.0 million per month through September 2004.

As part of the formation of Freeport LNG Development, L.P., Cheniere granted Contango a warrant to purchase 300,000 shares of Cheniere common stock. In June and September 2003, we exercised the warrant, purchasing 300,000 shares of Cheniere common stock. As of March 31, 2004, the 300,000 shares had been sold for a total realized gain of approximately $1.2 million.

In September 2003, we completed the sale of certain reserves in Brooks County, Texas for $5.0 million and recorded a gain of approximately $982,000. Proved reserves were 1.5 Bcfe and accounted for approximately $5.0 million of the Company’s discounted present value at 10% per annum as of June 30, 2003.

In December 2003, Contango and Republic Exploration sold their producing Gulf of Mexico leases for approximately $12.0 million. As a result of this sale, Contango recorded a gain of approximately $6.2 million. Properties included in the sale were Eugene Island 110, Grand Isle 28 and High Island 25-L. Contango received approximately $3.7 million in cash proceeds for its portion of the sale. Republic Exploration received cash proceeds of approximately $8.3 million for its portion of the sale. Republic Exploration subsequently made distributions of $3.0 million to its members, including a $1.0 million distribution to Contango.

In December 2003, we sold $8.0 million of our Series C preferred stock to a group of private institutional investors. The Series C preferred stock is perpetual and is convertible at the holders’ election at any time into shares of Contango common stock at a price of $6.00 per share. The dividend on the Series C Preferred Stock can be paid quarterly in cash at a rate of 6.0% per annum, or $480,000, or paid-in-kind at a rate of 7.5% per annum. We have filed a shelf registration statement with the Securities and Exchange Commission, which is effective, covering the 1,333,328 shares of common stock issuable upon conversion of the Series C preferred stock, together with an additional 1,417,685 shares of common stock that are issuable upon the exercise of certain stock options and warrants or may be issuable as a result of payment of the Series C preferred stock dividends in kind.

In January 2004, we converted all of the outstanding shares of our Series A and Series B preferred stock into 2,136,364 shares of common stock. The Series A and Series B preferred stock paid an 8.0% annual dividend. The conversion of these shares into common stock will save us $600,000 annually in preferred dividends. We have filed a shelf registration statement with the Securities and Exchange Commission, which is effective, covering these 2,136,364 shares of common stock, plus an additional 1,851,852 shares of common stock owned by Trust Company of the West, the holder of the Series A Preferred Stock.

Cash Outflows

For the nine months ended March 31, 2004, we spent approximately $8.6 million on various investing activities. Included in this total is approximately $5.2 million in exploration and development expenditures, $2.5 million invested primarily in Contango Offshore Exploration for offshore lease acquisitions, and $0.9 million of investment in our Freeport LNG project. During the nine months ended March 31, 2004, we drilled 11 wells in south Texas, four of which were successful. For the three months ended March 31, 2004, we drilled three wells, none of which were successful.

Additional capital expenditures through mid-summer 2004, depending on drilling success, could approach approximately $10.0 million. Included in this total are:

•

Approximately $1.0 million planned to be spent with Alta Resources to complete a recently drilled Queen City well in Duval County, Texas and to drill and, if successful, complete an offset Queen City location;

•

Approximately $0.8 million planned to be spent with Alta Resources to drill and complete a Frio well in Matagorda County, Texas;

•

Approximately $0.6 million to be spent with Ameritex to drill and, if successful, complete a Wilcox well in Zapata County, Texas;

•

Approximately $0.8 million of dry hole costs to drill an exploratory oil well with TPIC in southwestern France;

•

Approximately $1.0 million available for possible direct Contango investment in offshore exploratory wells;

•

Approximately $3.2 million in payments for offshore leases offered in the Gulf of Mexico lease sale held March 2004 where Contango Offshore Exploration was the apparent high bidder;

•

Approximately $1.0 million for seismic acquisitions, including approximately $0.4 for additional offshore Gulf of Mexico seismic and $0.6 million for seismic in Dimmit and Zavala Counties, Texas; and

•

Approximately $0.5 million for investment in our Freeport, Texas LNG project, including a $400,000 payment if FERC approval is obtained.

Additional spending can be anticipated based on ongoing prospect generation effort by our alliance partners. We expect Eugene Island 113B and Vermilion 73 will spud during the summer. We will not incur any capital costs for these wells, as our interest is carried.

We believe that our cash on hand, our anticipated cash flow from operations and funds available under our credit facility will be adequate to satisfy planned capital expenditures over the next 12 months. We may seek additional equity, sell assets or seek other financing to fund possible acquisitions and an expanded exploration program, and to take advantage of other opportunities that may become available. 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.

Credit Facility

Our credit facility is a secured, reducing revolving line of credit with Guaranty Bank, FSB, secured by our natural gas and oil reserves. In February 2004, the borrowing base was redetermined to $25.0 million in two tranches. Tranche A provides for a borrowing base of $23.0 million and matures on June 29, 2006. This amount reduces by $520,000 per month the first day of each month beginning March 1, 2004. Borrowings under Tranche A bear interest, at our option, at either (i) LIBOR plus two percent (2%) or (ii) the bank’s base rate plus one-fourth percent (1/4%) per annum. Additionally, we pay a quarterly commitment fee of three-eighths percent (3/8%) per annum on the average availability of Tranche A. Tranche B provides for a borrowing base of $2.0 million and matures on August 1, 2004. Borrowings under Tranche B will reduce by $520,000 per month the first day of each month following the date of borrowing, with the final reduction on August 1, 2004. Further, any amounts borrowed and repaid under Tranche B cannot be reborrowed. Borrowings under Tranche B bear interest, at the Company’s option, at either (i) LIBOR plus three percent (3%) or (ii) the bank’s base rate plus three-quarters percent (3/4%) per annum. Additionally, we pay a quarterly commitment fee of one-half percent (1/2%) per annum on the average availability under Tranche B.

The hydrocarbon borrowing base is subject to semi-annual redetermination based primarily on the value of our proved reserves. The credit facility requires the maintenance of certain ratios, including those related to working capital, funded debt to EBITDAX, and debt service coverage, as defined in the credit facility. Additionally, the credit facility contains certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell assets, pay dividends and reacquire or otherwise acquire or redeem capital stock. Failure to maintain required financial ratios or comply with the credit facility’s covenants can result in a default and acceleration of all indebtedness under the credit facility.

As of March 31, 2004, the Company’s long-term debt totaled $3.9 million, all of which was outstanding under Tranche A of the line of credit. The average interest rate on the Company’s long-term debt at March 31, 2004 was 3.3%. As of March 31, 2004, the Company was in compliance with its financial covenants, ratios and other provisions of the credit facility.

On May 12, 2004, we had approximately $0.2 million in cash on hand, $2.5 million borrowed under our credit facility and $21.0 million of unused bank borrowing capacity.

Natural Gas and Oil Reserves

The following table presents our estimated net proved, developed producing natural gas and oil reserves and the pre-tax net present value of our reserves at March 31, 2004, based on a reserve report generated by W.D. Von Gonten & Co. 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 developed producing reserves as of March 31, 2004 was determined by the March 31, 2004 prices of $5.35 per MMbtu for natural gas at the Houston Ship Channel and $35.76 per barrel of oil at West Texas Intermediate Posting, in each case before adjusting for basis and transportation costs. Our proved reserves are 91% natural gas.


	Proved Reserves as of March 31, 2004
Natural gas (MMcf)		16,929
Oil and condensate (MBbls)		294
Total proved reserves (MMcfe)		18,693

Pre-tax net present value (SEC guidelines)	$	57,790,543

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 on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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, unpredictable and are beyond our control. For the nine months ended March 31, 2004, a 10% fluctuation in the prices received for natural gas and oil production would have had an approximate $2.0 million impact on our revenues.

Item 4. Controls and Procedures

Kenneth R. Peak, our Chief Executive Officer and Chief Financial Officer, has carried out an evaluation of the effectiveness of the Company’s disclosure controls and procedures pursuant to Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this quarterly report. Based upon his evaluation, he has concluded that the Company’s disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic Securities and Exchange Commission filings.

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

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

None.

Item 2. Changes in Securities, Use of Proceed and Issuer Purchases of Equity Securities

None

Item 3. Defaults Upon Senior Securities

None.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Item 5. Other Information

None.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits:

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


Exhibit Number		Description
3.1		Certificate of Incorporation of Contango Oil & Gas Company, a Delaware corporation. (7)

3.2		Bylaws of Contango Oil & Gas Company, a Delaware corporation. (7)

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

3.4		Amendment to the Certificate of Incorporation of Contango Oil & Gas Company, a Delaware corporation. (15)

4.1		Facsimile of common stock certificate of the Company. (1)

4.2		Certificate of Designations, Preferences and Relative Rights and Limitations for Series C Senior Convertible Cumulative Preferred Stock of Contango Oil & Gas Company, a Delaware corporation. (19)

10.1		Agreement, dated effective as of September 1, 1999, between Contango Oil & Gas Company and Juneau Exploration, L.L.C. (2)

10.2		Securities Purchase Agreement between Contango Oil & Gas Company and Trust Company of the West, dated December 29, 1999. (12)

10.3		Warrant to Purchase Common Stock between Contango Oil & Gas Company and Trust Company of the West, dated December 29, 1999. (3)

10.4		Co-Sale Agreement among Kenneth R. Peak, Contango Oil & Gas Company and Trust Company of the West, dated December 29, 1999. (3)

10.5		Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Trust Company of the West. (4)

10.6		Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Fairfield Industries Incorporated. (4)

10.7		Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Juneau Exploration Company, L.L.C. (4)

10.8		Amendment dated August 14, 2000 to agreement between Contango Oil & Gas Company and Juneau Exploration Company, LLC. dated effective as of September 1, 1999. (5)

10.9		Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (8)

10.10		First Amendment dated as of January 8, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (9)

10.11		Asset Purchase Agreement by and among Juneau Exploration, L.P. and Contango Oil & Gas Company dated January 4, 2002. (9)

10.12		Asset Purchase Agreement by and among Mark A. Stephens, John Miller, The Hunter Revocable Trust, Linda G. Ferszt, Scott Archer and the Archer Revocable Trust and Contango Oil & Gas Company dated January 9, 2002. (10)

10.13		Second Amendment dated as of February 13, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (11)

10.14		Waiver dated as of March 25, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (11)



10.15		Option Purchase Agreement between Contango Oil & Gas Company and Cheniere Energy, Inc. dated June 4, 2002. (13)

10.16		Waiver and Third Amendment dated as of April 26, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (14)

10.17		Fourth Amendment dated as of September 9, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (14)

10.18		Fifth Amendment, effective June 1, 2003, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (16)

10.19		Sixth Amendment, effective September 1, 2003, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (18)

10.20		Seventh Amendment, effective September 1, 2003, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (21)

10.21		Securities Purchase Agreement dated December 12, 2003 by and between Contango Oil & Gas Company and the Purchasers Named Therein. (19)

10.22		Freeport LNG Development, L.P. Amended and Restated Limited Partnership Agreement dated February 27, 2003. (20)

10.23		Partnership Purchase Agreement among Contango Sundance, Inc., Contango Oil & Gas, Cheniere LNG, Inc. and Cheniere Energy, Inc. dated March 1, 2003. (20)

10.24		First Amendment, dated December 19, 2003, to Freeport LNG Development, L.P. Amended and Restated Limited Partnership Agreement dated February 27, 2003. (20)

10.25		Eighth Amendment, effective February 13, 2004, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. †

14.1		Code of Ethics. (17)

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

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 Form 10-SB Registration Statement, as filed with the Securities and Exchange Commission on October 16, 1998.

2.	Filed as an exhibit to the Company’s Form 10-QSB for the quarter ended December 31, 1999, as filed with the Securities and Exchange Commission on November 11, 1999.

3.	Filed as an exhibit to the Company’s Form 10-QSB for the quarter ended December 31, 1999, as filed with the Securities and Exchange Commission on February 14, 2000.

4.	Filed as an exhibit to the Company’s report on Form 8-K, dated August 24, 2000, as filed with the Securities and Exchange Commission of September 8, 2000.

5.	Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2000, as filed with the Securities and Exchange Commission on September 27, 2000.

6.	Filed as an exhibit to the Company’s report on Form 8-K, dated September 27, 2000, as filed with the Securities and Exchange Commission on October 3, 2000.

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

8.	Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2001, as filed with the Securities and Exchange Commission on September 21, 2001.

9.	Filed as an exhibit to the Company’s report on Form 8-K, dated January 4, 2002, as filed with the Securities and Exchange Commission on January 8, 2002.

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

11.	Filed as an exhibit to the Company’s report filed on Form 10-QSB for the quarter ended March 31, 2002, dated May 2, 2002, as filed with the Securities and Exchange Commission.

12.	Filed as an exhibit to the Company’s Form 10-QSB/A for the quarter ended December 31, 1999, as filed with the Securities and Exchange Commission on June 4, 2002.

13.	Filed as an exhibit to the Company’s Registration Statement on Form S-1 (Registration No. 333-89900) as filed with the Securities and Exchange Commission on June 14, 2002.

14.	Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2002, as filed with the Securities and Exchange Commission on September 26, 2002.

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

16.	Filed as an exhibit to the Company’s report on Form 8-K, dated June 17, 2003, 2002, as filed with the Securities and Exchange Commission on June 18, 2003.

17.	Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2003, as filed with the Securities and Exchange Commission on September 22, 2003.

18.	Filed as an exhibit to the Company’s report filed on Form 10-Q for the quarter ended September 30, 2003, dated November 12, 2003, as filed with the Securities and Exchange Commission.

19.	Filed as an exhibit to the Company’s report on Form 8-K, dated December 12, 2003, as filed with the Securities and Exchange Commission on December 17, 2003.

20.	Filed as an exhibit to the Company’s report on Form 8-K, dated December 19, 2003, as filed with the Securities and Exchange Commission on December 23, 2003.

21.	Filed as an exhibit to the Company’s report filed on Form 10-Q for the quarter ended December 31, 2003, dated February 13, 2004, as filed with the Securities and Exchange Commission.

(b) Report on Form 8-K:

Form 8-K, event date March 17, 2004 (Items 5 and 7), announcing that two of the Contango’s affiliated companies bid on 37 blocks and were the apparent high bidders on 24 blocks offered at the Central Gulf of Mexico Lease Sale #190 held March 17, 2004 in New Orleans, as filed on March 18, 2004.

Form 8-K, event date February 24, 2004 (Items 5 and 7), reporting the Company filed a registration statement on Form S-3 with the Securities and Exchange Commission for a secondary offering by certain selling stockholders, as filed on February 24, 2004.

Form 8-K, event date February 13, 2004 (Items 5, 7 and 12), reporting the results for the quarter ended December 31, 2003, as filed on February 13, 2004.

SIGNATURES

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


	CONTANGO OIL & GAS COMPANY

Date: May 12, 2004	By:	/s/ KENNETH R. PEAK
		Kenneth R. Peak
		Chairman and Chief Executive Officer
		(Principal Executive and Financial Officer)

Date: May 12, 2004	By:	/s/ LESIA BAUTINA
		Lesia Bautina
		Vice President and Controller
		(Principal Accounting Officer)