Edgar Filing: CONTANGO OIL & GAS CO

Form 10-QSB

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-QSB

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2003

Commission file number 000-24971

CONTANGO OIL & GAS COMPANY

(Exact name of small business issuer 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)

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 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 ¨

The total number of shares of common stock, par value $0.04 per share, outstanding as of May 12, 2003 was 9,262,141.

Transitional Small Business Disclosure Format (check one): Yes ¨ No x

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-QSB

FOR THE NINE MONTHS ENDED MARCH 31, 2003

TABLE OF CONTENTS

		Page
	PART I—FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets as of March 31, 2003 and June 30, 2002	3
	Consolidated Statements of Operations for the three and nine months ended March 31, 2003 and 2002	5
	Consolidated Statements of Cash Flows for the nine months ended March 31, 2003 and 2002	6
	Consolidated Statement of Shareholders’ Equity for the nine months ended March 31, 2003	7
	Notes to the Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Controls and Procedures	34

	PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	34
Item 2.	Changes in Securities and Use of Proceeds	34
Item 3.	Defaults Upon Senior Securities	34
Item 4.	Submission of Matters to a Vote of Security Holders	34
Item 5.	Other Information	34
Item 6.	Exhibits and Reports on Form 8-K	35
Signatures		38
Certification of Chief Executive Officer and Chief Financial Officer		39

WEBSITE ACCESS TO REPORTS

Our Internet address is www.mcfx.biz. As required, as of November 15, 2002, we make available free of charge on or through our Internet website our annual report on Form 10-KSB, quarterly reports on Form 10-QSB and current reports on Form 8-K filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

	March 31, 2003			June 30, 2002
	(Unaudited)

CURRENT ASSETS:
Cash and cash equivalents	$	1,085,413		$	2,726,845
Accounts receivable, net		6,571,066			5,220,453
Advances to operators		—			597,294
Price hedge contracts		—			57,726
Income taxes receivable		300,000			—
Other		183,299			184,437

Total current assets		8,139,778			8,786,755

PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties		51,267,886			46,565,998
Unproved properties, not being amortized		2,035,387			3,650,558
Furniture and equipment		126,281			188,884
Accumulated depreciation, depletion and amortization		(19,434,962	)		(13,056,575	)

Total property, plant and equipment		33,994,592			37,348,865

OTHER ASSETS:
Cash and other assets held by affiliates		1,557,592			4,732,726
Investment in LNG project		750,000			750,000
Deferred income tax asset		854,351			—
Investment in partnership		72,500			72,500
Other assets		121,480			148,670

Total other assets		3,355,923			5,703,896

TOTAL ASSETS	$	45,490,293		$	51,839,516

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, 2003			June 30, 2002
	(Unaudited)

CURRENT LIABILITIES:
Accounts payable	$	591,611		$	613,537
Accrued exploration and development		347,075			517,000
Income taxes payable		—			1,040,788
Price hedge contracts		37,382			183,400
Hedge payable		445,500			525,870
Other accrued liabilities		552,692			648,654
Current portion of long-term debt		6,710,000			1,330,000

Total current liabilities		8,684,260			4,859,249


LONG-TERM DEBT		16,780,000			18,103,920

OTHER LONG-TERM LIABILITIES		333,333			—

DEFERRED INCOME TAX LIABILITY		—			3,777,864

ASSET RETIREMENT OBLIGATIONS		196,406			—

SHAREHOLDERS’ EQUITY:
Convertible preferred stock, 8%, Series A, $0.04 par value, 5,000 shares authorized, 2,500 shares issued and outstanding at March 31, 2003 and June 30, 2002, liquidation preference of $1,000 per share		100			100
Convertible preferred stock, 8%, Series B, $0.04 par value, 10,000 shares authorized, 5,000 shares issued and outstanding at March 31, 2003 and June 30, 2002, liquidation preference of $1,000 per share		200			200
Common stock, $0.04 par value, 50,000,000 shares authorized, 11,837,141 shares issued and 9,262,141 outstanding at March 31, 2003, 11,618,282 shares issued and 9,043,282 outstanding at June 30, 2002		472,732			464,732
Additional paid-in capital		21,766,329			21,236,701
Treasury stock at cost (2,575,000 shares)		(6,180,000	)		(6,180,000	)
Retained earnings		3,436,933			9,576,750

Total shareholders’ equity		19,496,294			25,098,483

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	45,490,293		$	51,839,516

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,
	2003			2002			2003			2002
REVENUES:
Natural gas and oil sales	$	10,061,351		$	5,919,715		$	24,793,109		$	15,908,607
Gain (loss) from hedging activities		(5,230,672	)		90,789			(5,416,998	)		4,145,216

Total revenues		4,830,679			6,010,504			19,376,111			20,053,823

EXPENSES:
Operating expenses		1,448,367			833,874			4,179,166			2,525,620
Exploration expenses		3,588,654			—			15,496,798			2,522,836
Depreciation, depletion and amortization		1,942,144			2,931,618			6,518,654			6,044,823
General and administrative expenses		391,483			525,235			1,464,576			1,331,146

Total expenses		7,370,648			4,290,727			27,659,194			12,424,425

INCOME (LOSS) FROM OPERATIONS		(2,539,969	)		1,719,777			(8,283,083	)		7,629,398

Interest expense		(177,860	)		(87,882	)		(531,763	)		(97,244	)
Interest income		6,498			34,222			27,663			169,156
Gain on sale of assets and other		—			254,619			36,150			373,539

INCOME (LOSS) BEFORE INCOME TAXES		(2,711,331	)		1,920,736			(8,751,033	)		8,074,849

Benefit (provision) for income taxes		948,966			(669,905	)		3,061,216			(2,826,063	)

NET INCOME (LOSS)		(1,762,365	)		1,250,831			(5,689,817	)		5,248,786
Preferred stock dividends		150,000			150,000			450,000			450,000

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(1,912,365	)	$	1,100,831		$	(6,139,817	)	$	4,798,786

NET INCOME (LOSS) PER SHARE:
Basic	$	(0.21	)	$	0.10		$	(0.68	)	$	0.42

Diluted	$	(0.21	)	$	0.09		$	(0.68	)	$	0.37

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		9,158,755			11,427,532			9,080,392			11,477,836

Diluted		9,158,755			14,319,063			9,080,392			14,301,024

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,
	2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(5,689,817	)	$	5,248,786
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		6,518,654			6,044,823
Exploration expenditures		4,578,620			2,285,599
Increase (decrease) in deferred income taxes		(4,632,215	)		571,138
Gain on sale of assets and other		(36,150	)		(373,539	)
Unrealized hedging (gain) loss		(88,292	)		1,137,880
Stock-based compensation		81,628			9,317
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(1,650,613	)		1,589,796
(Increase) decrease in prepaid insurance		87,132			(74,015	)
(Decrease) increase in accounts payable		(216,733	)		3,188,569
Decrease in other accrued liabilities		(744,269	)		(537,732	)
(Decrease) increase in income taxes payable		(590,788	)		1,061,925
Other		(37,660	)		27,684

Net cash (used) provided by operating activities		(2,420,503	)		20,180,231

CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures		(2,559,416	)		(7,780,894	)
Decrease (increase) in cash and other assets held by affiliates		900,000			(1,385,254	)
Additions to furniture and equipment		(16,238	)		(78,246	)
(Decrease) increase in advances to operators		557,560			(60,974	)
Purchase of proved producing reserves		(2,599,485	)		(19,956,452	)
Acquisition costs		(3,100	)		(144,075	)
Proceeds from sale of assets and other		—			266,448

Net cash used in investing activities		(3,720,679	)		(29,139,447	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		22,065,000			24,300,000
Repayments under credit facility		(17,525,000	)		(6,100,000	)
Purchase of treasury shares		—			(6,180,000	)
Exercise of warrants		456,000			—
Preferred stock dividends		(450,000	)		(450,000	)
Debt issue costs		(46,250	)		(86,399	)

Net cash provided by financing activities		4,499,750			11,483,601

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(1,641,432	)		2,524,385
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		2,726,845			1,586,342

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	1,085,413		$	4,110,727

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for taxes	$	2,405,788		$	1,200,000

Cash paid for interest	$	485,634		$	52,417

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(Unaudited)

	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
Net income	—		—	—		—		—		—			366,868			366,868
Expense of stock options	—		—	—		—		21,083		—			—			21,083
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

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

Net loss	—		—	—		—		—		—			(1,762,365	)		(1,762,365	)
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
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

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 thereto included in Contango Oil & Gas Company’s (“Contango” or the “Company”) Form 10-KSB for the fiscal year ended June 30, 2002. The results of operations for the three and nine months ended March 31, 2003 are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2003.

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, stock options and asset retirement obligations.

Successful Efforts Method of Accounting. Contango 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. Proved natural gas and oil properties are reviewed quarterly, and if required, the proved properties are written down to their estimated fair value. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying amount, and any such impairment is charged to expense in the period. Estimated fair value includes the estimated present value of all reasonably expected future production, prices and costs. 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 geological and geophysical costs, seismic reprocessing costs and the cost of carrying and retaining undeveloped properties, are charged to expense when incurred. The provision for depreciation, depletion and amortization is based on the capitalized costs as determined above and is on a cost center by cost center basis using the units of production method, with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves. The Company creates cost centers on a well-by-well basis for all of its natural gas and oil activities.

Consolidation Principles. 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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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.

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.

During the quarter ended December 31, 2002, 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 $224,000, respectively, for the nine months ended March 31, 2003. 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.

Hedge Accounting. In June 1998, the Financial Accounting Standards Board, or “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, establishes 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 value. The statement requires that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge criteria are met. Although the derivative transactions the Company engages in are designed as economic hedges for a portion of future natural gas and oil production, the Company has elected not to designate these as “hedges” under SFAS 133. Accordingly, the Company recognizes the changes in the derivative’s fair value in its income statement under “Gain (loss) from hedging activities”.

Stock Options. The Company expenses the cost of all Contango stock options beginning with stock options granted during the fiscal year ended June 30, 2002. The Company has adopted the fair value based method of recording stock options contained in SFAS 123, “Accounting for Stock-Based Compensation” and the prospective method transition provision of SFAS No. 148, “Accounting for Stock Based Compensation—Transition and Disclosure, an Amendment of FAS No. 123”. All employee stock option grants are expensed over each stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. The Company recorded an expense of $28,601 and $81,628 for the three and nine months ended March 31, 2003 from the application of this accounting standard.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Freeport LNG Development, L.P. In March 2003, The Company exercised an option to purchase from Cheniere Energy, Inc. a 10% limited partnership interest in Freeport LNG Development, L.P., a limited partnership formed to develop a LNG receiving terminal in Freeport, Texas. The Company’s commitment is $2.3 million, $750,000 of which has already been paid. The balance will be paid in twelve $100,000 monthly payments commencing June 15, 2003, with an additional $400,000 due upon receipt of FERC approval for the project. The Company own $150,000 shares of Cheniere Energy common stock for which it paid $225,000 and 150,000 warrants to purchase Cheniere Energy common stock at $2.50 per share. On March 31, 2003, The Company announced that Freeport LNG had submitted a filing to the Federal Energy Regulatory Commission (FERC) for the construction of the LNG receiving terminal. A response from the FERC is not expected prior to mid-2004.

Recently Issued Accounting Standards. The FASB has issued three new pronouncements, SFAS 143, “Accounting for Asset Retirement Obligations”, SFAS 144, “Accounting for Impairment or Disposal of Long-Lived Assets” and SFAS 146, “Accounting for Costs Associated with Exit and Disposal Activities”.

SFAS 143 requires companies to record a liability relating to the retirement of tangible long-lived assets. When the liability is initially recorded, a company increases the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company adopted SFAS 143 on July 1, 2002 and recorded an asset retirement obligation of $194,866 related to the Company’s legal obligation to plug and abandon its oil and gas wells. The Company determined that the asset retirement obligation as of July 1, 2001 would not be materially different than the liability recorded on July 1, 2002. The Company considers that the cumulative effect of initially applying SFAS 143 is not material to the Consolidated Statement of Operations.

SFAS 144 addresses the financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS 144 supersedes SFAS 121 but retains its fundamental provisions for the (a) recognition and measurement of impairment of long-lived assets to be held and used and (b) measurement of long-lived assets to be disposed of by sale. SFAS 144 also supersedes the accounting and reporting portions of APB Opinion No. 30 for segments of a business to be disposed of but retains the requirement to report discontinued operations separately from continuing operations and extends that reporting to a component of an entity that either has been disposed of or is classified as “held for sale”. This standard is effective for fiscal years beginning after December 15, 2001. The adoption of SFAS 144 was not significant to the Company’s financial statements.

SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)”. This standard is effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. The Company does not anticipate the adoption of SFAS 146 will be significant to the Company’s financial statements.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2. Natural Gas and Oil Exploration Risk

The Company’s future financial condition and results of operations depends on the cost of finding, acquiring, developing and producing reserves and upon prices received for its natural gas and oil production. Substantially all of its production is sold under various terms and arrangements at prevailing market prices. 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; the high risk nature of exploration, the fact that drilling activities may not be successful, the fact that natural gas and oil are a depleting asset, access to additional capital; adverse 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.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

3. Liquidity

Management believes that cash on hand, anticipated cash flow from operations and availability under the Credit Facility (as defined in footnote 4) will be adequate to satisfy currently planned capital expenditures over the next 12 months. The Company may need to seek additional equity or other financing opportunities to fund acquisitions, pursue an expanded exploration program or take advantage of other opportunities that may become available. In addition, the Company may from time-to-time as part of its business strategy sell some or a substantial portion of its assets as a means of raising capital to further its exploration activities. The availability of funds or the Company’s ability to sell assets on a favorable basis 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.

4. Long-Term Debt

Contango has a secured, reducing revolving line of credit with Guaranty Bank, FSB (the “Credit Facility”) that matures in June 2004. The hydrocarbon borrowing base as of March 31, 2003 was $25.5 million and reduces by $670,000 the first day of each month. The hydrocarbon borrowing base is subject to semi-annual redetermination based primarily on the value of Contango’s proved reserves. Borrowings under the Credit Facility bear interest, at Contango’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 under the Credit Facility. 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 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, 2003, the Company’s long-term debt was as follows:

Outstanding under the Credit Facility	$	23,490,000
Current portion of the Credit Facility		(6,710,000	)

		16,780,000
Other long-term liabilities		333,333

Total long-term debt	$	17,113,333

As of March 31, 2003, the Company was in compliance with its financial covenants, ratios and other provisions of the Credit Facility. The average interest rate on the Company’s long-term debt at March 31, 2003 was 3.28%.

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 common share is presented in the tables below.

	Three Months Ended March 31, 2003								Three Months Ended March 31, 2002
	Loss			Shares		Per Share			Income		Shares	Per Share
Basic:
Net income (loss) attributable to common stock	$	(1,912,365	)	9,158,755		$	(0.21	)	$	1,100,831	11,427,532	$	0.10

Effect of Dilutive Securities:
Stock options and warrants		(a	)	(a	)					—	755,168
Series A preferred stock		(a	)	(a	)					50,000	1,000,000
Series B preferred stock		(a	)	(a	)					100,000	1,136,363

Diluted:
Net income (loss) attributable to common stock	$	(1,912,365	)	9,158,755		$	(0.21	)	$	1,250,831	14,319,063	$	0.09

(a)

Anti-dilutive.

	Nine Months Ended March 31, 2003								Nine Months Ended March 31, 2002
	Loss			Shares		Per Share			Income		Shares	Per Share
Basic:
Net income (loss) attributable to common stock	$	(6,139,817	)	9,080,392		$	(0.68	)	$	4,798,786	11,477,836	$	0.42

Effect of Dilutive Securities:
Stock options and warrants		(a	)	(a	)					—	686,825
Series A preferred stock		(a	)	(a	)					150,000	1,000,000
Series B preferred stock		(a	)	(a	)					300,000	1,136,363

Diluted:
Net income (loss) attributable to common stock	$	(6,139,817	)	9,080,392		$	(0.68	)	$	5,248,786	14,301,024	$	0.37

(a)

Anti-dilutive.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

6. Commodity Price Hedges

Contango periodically enters into commodity derivative contracts. These contracts, which are placed with companies that the Company believes to be of high credit quality and minimal credit risks, may take the form of futures contracts, swaps or options. The derivative contracts call 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 table below sets forth the Company’s hedging activities for the periods indicated.

	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	)

	Three Months Ended									YTD Total March 31, 2002
	September 30, 2001			December 31, 2001			March 31, 2002			YTD Total March 31, 2002
Mark-to-market reversal of prior period unrealized recognized gain	$	(888,400	)	$	(1,682,408	)	$	(864,528	)	$	(888,400	)
Net cash received from swap settlements		3,689,651			388,648			1,204,797			5,283,096
Mark-to-market gain (loss) unrealized		1,682,408			864,528			(249,480	)		(249,480	)

Gain (loss) from hedging activities	$	4,483,659		$	(429,232	)	$	90,789		$	4,145,216

The table below sets forth the Company’s pricing and notional volumes on open commodity derivative contracts as of March 31, 2003.

Contract Description	Term	Strike Price(1)		Quantity(1)
Natural gas puts owned	05/2003 – 10/2003	$	4.50	10,000/day
Natural gas puts owned	11/2003 – 12/2003	$	4.00	10,000/day
Natural gas calls owned	05/2003	$	5.50	1,000/day
Natural gas calls sold	05/2003 – 07/2003	$	5.25	5,000/day
Natural gas calls sold	06/2003 – 07/2003	$	5.50	3,000/day
Natural gas calls sold	08/2003 – 10/2003	$	6.00	8,000/day

(1)

Prices and quantities per MMbtu.

Although these transactions were designed as economic hedges for a portion of future natural gas and oil production, the Company has elected not to designate these as “hedges” under SFAS No. 133. As a result, gains and losses, representing changes in these derivative instruments’ mark-to-market values, are recognized currently in Contango’s quarterly earnings. The Company’s derivative position as of March 31, 2003 had a mark-to-market loss of $37,382.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Because these open contracts are marked-to-market on a daily basis, the Company is exposed to wide swings in its exposure and could be subject to significant hedging losses in the event of a significant increase in natural gas prices. While the use of hedging arrangements limits the downside risk of adverse price movements, they also may limit future revenue from favorable price movements. The use of hedging transactions also involves the risk that the counter parties will be unable to meet the financial terms of such transactions. The terms of the agreements with certain counter parties provide that if the mark-to-market loss to that counter party exceeds $1.0 million, Contango will have to provide collateral to cover the potential loss position.

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-QSB and in our Form 10-KSB for the fiscal year ended June 30, 2002, previously filed with the Securities and Exchange Commission.

Uncertainty of Forward-Looking Statements and Information

Some of the statements made in this Form 10-QSB 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 and property acquisitions

•

Planned or potential sale of assets

•

Hedging results

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:

•

Risks associated with exploration

•

Ability to raise capital to fund capital expenditures

•

Ability to find, acquire, develop and produce new properties and market production

•

Volatility of natural gas and oil prices

•

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

•

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 positions

•

Ability to find and retain skilled personnel

•

Strength and financial resources of competitors

•

Regulatory developments

•

Environmental risks

•

General economic conditions

You should not unduly rely on these forward-looking statements in this Form 10-QSB, as they speak only as of the date of this Form 10-QSB. 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-QSB 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, 2002 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.

Contango Oil & Gas Company

We are an independent natural gas and oil company that explores for, acquires, produces and sells natural gas and crude oil. We also own a 10% partnership interest in a proposed LNG terminal in Freeport, Texas.

Our exploration and production efforts are currently focused onshore on the Texas Gulf Coast and offshore in the Gulf of Mexico. Our primary source of production currently is onshore in south Texas. Our initial exploration efforts were concentrated in properties located in our South Texas Exploration Program (“STEP”), where from May 2000 to February 2002 we drilled 41 wells, resulting in 31 commercial successes. We are also participating in two 3-D seismic shoots nearby our STEP production. Our working interest in these two shoots is 47.5%. Based on the evaluation of the first of these seismic shoots, we have drilled nine wells since January 2003, seven of which have been successful, and we have another two wells scheduled to drill. We are continuing to evaluate the data from this first shoot and are currently in the field acquiring data for our second seismic shoot.

While our south Texas interests currently account for nearly all of our production, we also have interests in producing properties located offshore in the Gulf of Mexico and participate in offshore exploration in the Gulf of Mexico both directly and through our ownership interests in Republic Exploration, L.L.C. (33.3% owned), Magnolia Offshore Exploration, L.L.C. (50% owned) and Contango Offshore Exploration, L.L.C. (66.7% owned).

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 proven geoscientists. Our prospect generation and evaluation functions are performed by our alliance partner, Juneau Exploration, L.P. (“JEX”). This proven group of four explorationists with 15 to 20 years of experience each has demonstrated its ability

to find reserves both onshore and offshore in the Gulf of Mexico. In our experience, only a select group of explorationists are able to consistently and profitably find natural gas and oil. Our STEP properties and our recent discoveries, both onshore and offshore in the Gulf of Mexico, were on prospects generated by JEX. Our principal exploration strategy is to fund exploration prospects generated by JEX.

Negotiated acquisitions of proved properties. Since January 1, 2002, we have spent approximately $26.0 million to acquire approximately 14.0 Bcfe of proved developed producing reserves of natural gas and oil. We will 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.

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.

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 the industry in general and administrative costs per employee. We plan to continue our program of outsourcing geological, geophysical, reservoir engineering and land functions, and partnering with cost efficient operators whenever possible. We currently have four employees.

Structuring transactions to minimize front-end investments. We seek to maximize returns on capital by minimizing, where possible, up-front investments of our own capital in acreage, seismic data and prospect generation. We want our key 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 alliance ventures with companies and individuals that offer attractive investment opportunities. These opportunities may include domestic or foreign exploration prospects, as well as investments in downstream natural gas assets. We recently invested in a proposed liquefied natural gas plant in Freeport, Texas.

Structuring incentives to drive behavior. We believe that equity ownership aligns the interests of our partners, employees and stockholders. Our directors and executive officers currently hold approximately 15% of our outstanding common stock. In addition, our alliance agreement with JEX requires JEX to co-invest in every prospect that it recommends to us and provides that JEX is compensated only when wells are successfully drilled.

Exploration Alliance with JEX

Under a September 1999 agreement, 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 in the recommended prospects and property acquisitions. We also issued 200,000 shares of our common stock to JEX and granted JEX options to purchase 400,000 shares of our common stock. The vesting of those options depends on the success of certain prospects and reserves in which we have invested under the agreement. As of March 31, 2003, options to purchase 300,000 shares of Contango common stock have vested.

Contango is normally responsible for acquiring, shooting or bearing the cost to reprocess 3-D seismic data and acquiring leasehold positions. JEX typically pays all other costs of generating and preparing a prospect to drill ready status. When drilling begins on a prospect, we are obligated to assign to JEX an overriding royalty interest in our working interest in the prospect. Our agreement with JEX states that this overriding royalty interest shall equal 3.3% of our working interest in the prospect. In practice, a majority of this royalty interest is assigned to the JEX exploration team. In addition, when our revenues from prospects we invest in under the agreement, 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 JEX 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.

Onshore Operations

Exploration. Our exploration and production efforts are currently focused onshore on the Texas Gulf Coast and offshore in the Gulf of Mexico. Our primary source of production currently is onshore in south Texas. Our initial exploration efforts were concentrated in properties located in our South Texas Exploration Program (“STEP”), where from May 2000 through February 2002 we drilled 41 wells, resulting in 31 commercial successes. We are also participating in two 3-D seismic shoots nearby our STEP production. Our working interest in these two shoots is 47.5%. Based on the evaluation of the first of these seismic shoots, we have drilled nine wells since January 2003, seven of which have been successful, and we have identified two more wells that we expect to drill prior to June 30, 2003. We are continuing to evaluate the data from this first shoot and are currently in the field acquiring data for our second seismic shoot. We expect to be able to begin prospect identification in the August through September 2003 timeframe. We also have acquired 2,000 square miles of 3-D seismic data in the Texas Gulf Coast at a cost of approximately $700,000.

We recently agreed in principle to acquire for an initial investment of $1.3 million an 80.5% limited partnership interest in a newly formed limited partnership formed to conduct exploration and acquisition activities onshore in the Gulf Coast. We expect the partnership documents to be finalized by the end of May 2003 at which time we will fund our initial investment. The other limited partners are JEX (9.5%) and a private company (9.0%). The private company, which also serves as the General Partner, is entitled to a 1.5% management fee on monthly natural gas and oil revenues and an assignment of 20% of our limited partnership interest after we have recouped our investment.

Production. Current net production is approximately 16.0 MMcf of natural gas and 300 barrels of oil per day.

Offshore Operations

Contango. Contango directly and through various offshore joint ventures conducts exploration activities in the shallow waters of the Gulf of Mexico. To date, Contango has acquired a direct interest in seven offshore leases. We participated directly in the drilling of two leases in 2000, one of which has a previously producing well that is shut in pending abandonment and the other of which has a producing well. Of the remaining five lease blocks, we have farmed out three, resulting in three successful wells on

two of the blocks that are expected to go on line the summer of 2003. We expect these three wells to begin production this summer at approximately 30.0 MMcf and 2,500 barrels of oil per day. Based on anticipated production rates and current prices, we expect Contango and its affiliates will earn their back-in working interest in the January to March 2004 timeframe. We expect to receive $400,000 to $500,000 per month cash flow at back-in. We have two remaining blocks available for farmout (see table “Offshore Operations and Properties” below).

Contango also owns an equity interest in Republic Exploration LLC, Magnolia Offshore Exploration LLC and Contango Offshore Exploration LLC formed for the purpose of generating exploration opportunities in the Gulf of Mexico. These limited liability companies (“LLCs”) have collectively licensed approximately 3,700 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, one or more of these LLCs may elect to retain direct working interest participations in their prospects, and 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 has invested approximately $6.7 million in cash in Republic Exploration since its formation in August 2000 for a 33.3% interest in Republic Exploration. The other members of Republic Exploration are JEX, its managing member, and a privately held company. Both have comprehensive offshore experience. Republic Exploration holds a non-exclusive license to approximately 1,400 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.

Since inception, Republic Exploration has acquired 11 offshore leases. Of the 11, Republic Exploration has entered into farm-out agreements with respect to seven. Of these seven leases, three have been drilled resulting in four completed wells, three have been unsuccessfully drilled and one is expected to commence drilling in the fall of 2003. Under the farm-out agreements, Republic Exploration is carried on exploration and development activities and receives a reversionary interest upon payout of each block; therefore, it will not own an interest or receive any cash flow in a block until after the occurrence of payout. The remaining four blocks are available for farm out (see table “Offshore Operations and Properties” below). Republic Exploration participated in the Central Gulf of Mexico Lease Sale 185 in March 2003, where it was the apparent high bidder on one lease block. The award is still pending with the MMS.

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. Viosca Knoll 211 has been farmed out, with drilling operations expected to commence in the third quarter of 2003. This lease is subject to a 3.3% overriding royalty interest in favor of the JEX exploration team and a net profits interest in favor of the entity that contributed the 3-D seismic data. The remaining two blocks are available for farm-out (see table “Offshore Operations and Properties” below). In November 2002, the members made the decision to limit the activities of Magnolia Offshore Exploration to its three existing leases; thus, no additional leases will be acquired. Contango’s current investment in Magnolia Offshore Exploration is approximately $763,000.

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. To date, Contango Offshore Exploration has invested approximately $6.7 million to acquire and reprocess 2,294 blocks of 3-D seismic data in the Gulf of Mexico. All leases will be subject to a 3.3% overriding royalty interest in favor of the JEX exploration team. Contango Offshore Exploration participated in the March 2003 Central Gulf of Mexico Lease Sale #185, where it was awarded two lease blocks and was apparent high bidder on two other lease blocks, which are still pending with the MMS (see table “Offshore Operations and Properties” below).

Production. Our current offshore production and cash flow is not significant. We expect this to change in the January to March 2004 timeframe when we anticipate earning an after payout back-in working interest in several of our offshore prospects that have been successful. We anticipate our initial cash flow, based on current anticipated decline rates and current prices, to be in the range of $400,000 to $500,000 per month.

Offshore Properties

The following table lists offshore Gulf of Mexico blocks that have been previously leased or are currently leased by us and related entities as well as certain other information with respect to the offshore blocks as of May 12, 2003:

Area/Block

Contango

Republic

Exploration

Magnolia

Offshore

Exploration

Contango

Offshore

Exploration

Date

Acquired

Status

Brazos 436

—

Jul-00

Shut in; pending abandonment

Eugene Island 28

—

Mar-00

Producing

Eugene Island 110

—

Jul-01

Well #1; production expected to go online summer 2003

Well #2; production expected to go online summer 2003

Grand Isle 24

—

Apr-01

Dry hole; block released

Grand Isle 28

—

Apr-01

Well #1; production expected to go online summer 2003

East Cameron 107

—

May-01

Available for farm-out

Eugene Island 113B

—

May-01

Farmed out; expected to spud 3Q2003

High Island 25L, N/2NE

—

Jan-01

Producing

High Island 53L, NE,NW

—

Oct-00

Available for farm-out

Galveston 149L

—

Jul-00

Dry hole; block released

West Cameron 200

—

May-02

Dry hole; block released

Vermilion 73

—

Jul-02

Available for farm-out

West Delta 36

—

May-02

Available for farm-out

Ship Shoal 155

—

May-02

Available for farm-out

Viosca Knoll 75

—

May-02

Available for farm-out

Viosca Knoll 211

—

Jul-02

Farmed out; expected to spud 3Q2003

Viosca Knoll 167

—

May-03

Available for farm-out

Vermillion 231

—

May-03

Available for farm-out

Total blocks

The following table sets forth the interests owned by Contango and related entities in the Gulf of Mexico as of May 12, 2003:

Area/Block

Location

Contango

Republic

Exploration(1)

Magnolia

Offshore

Exploration(1)

Contango

Offshore

Exploration(1)

NRI

Brazos 436

OCS (WGOM)

13.6

10.8

Eugene Island 28

OCS (CGOM)

21.4

15.3

Eugene Island 110

OCS (CGOM)

(2)

Grand Isle 28

OCS (CGOM)

(2)

East Cameron 107

OCS (CGOM)

33.8

27.0

66.2

53.0

Eugene Island 113B

OCS (CGOM)

(2)

High Island 25L, N/2 NE

TX State Waters

(3)

High Island 53L, NE, NW

TX State Waters

100.0

74.2

Vermilion 73

OCS (CGOM)

100.0

80.0

West Delta 36

OCS (CGOM)

100.0

80.0

Ship Shoal 155

OCS (CGOM)

100.0

80.0

Viosca Knoll 75

OCS (CGOM)

100.0

80.0

Viosca Knoll 211

OCS (CGOM)

(4)

Viosca Knoll 167

OCS (CGOM)

100.0

80.0

Vermillion 231

OCS (CGOM)

100.0

80.0

Indicates no interest in lease block.

(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)

At project payout, Contango and Republic Exploration will have the option to take a 25% working interest (8.44% WI/ 6.75% NRI and 16.56% WI/13.25% NRI, respectively) or a 10% overriding royalty interest (3.4% and 6.6%, respectively).

(3)

At project payout, Republic Exploration will receive a 25% working interest (19.2% net revenue interest).

(4)

At project payout, Magnolia Offshore Exploration will have the option to take a 25% working interest (20% net revenue interest, subject to a third party net profits interest) or a 10% overriding royalty interest (subject to a third party net profits interest).

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., a limited partnership formed to develop a LNG receiving terminal in Freeport, Texas. Our commitment is $2.3 million, $750,000 of which has already been paid. The balance will be paid in twelve $100,000 monthly payments commencing June 15, 2003, with an additional $400,000 due upon receipt of FERC approval for the project. We own $150,000 shares of Cheniere Energy common stock for which we paid $225,000 and 150,000 warrants to purchase Cheniere Energy common stock at $2.50 per share. On March 31, 2003, we announced that Freeport LNG had submitted a filing to the Federal Energy Regulatory Commission (FERC) for the construction of the LNG receiving terminal. A response from the FERC is not expected prior to mid-2004.

Critical 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. Our critical accounting principles, which we describe below, relate to the successful efforts method for costs related to natural gas and oil activities, consolidation principles, accounting for financial instruments, stock options and asset retirement obligations.

Successful Efforts Method of Accounting. We follow 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. Proved natural gas and oil properties are reviewed quarterly, and if required, the proved properties are written down to their estimated fair value. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying amount, and any such impairment is charged to expense in the period. Estimated fair value includes the estimated present value of all reasonably expected future production, prices and costs. 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 geological and geophysical costs, seismic reprocessing costs and the cost of carrying and retaining undeveloped properties are charged to expense when incurred. The provision for depreciation, depletion and amortization is based on the capitalized costs as determined above and is on a cost center by cost center basis using the units of production method, with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves. We create cost centers on a well-by-well basis for all of our natural gas and oil activities.

Consolidation Principles. Our 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.

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.

Hedge Accounting. In June 1998, the Financial Accounting Standards Board, or “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, establishes 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 value. The statement requires that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge criteria are met. Although the derivative transactions we engage in are designed as economic hedges for a portion of future natural gas and oil production, we have elected not to designate these as “hedges” under SFAS 133. Accordingly, we recognize the changes in the derivative’s fair value in our income statement under “Gain (loss) from hedging activities”.

Stock Options. We expense the cost of all Contango stock options beginning with stock options granted during the fiscal year ended June 30, 2002. We have adopted the fair value based method of recording stock options contained in SFAS 123, “Accounting for Stock-Based Compensation” and the prospective method transition provision of SFAS No. 148, “Accounting for Stock Based Compensation—Transition and Disclosure, an Amendment of FAS No. 123”. All employee stock option grants will be expensed over each stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. We recorded an expense of $28,601 and $81,628 for the three and nine months ended March 31, 2003 from the application of this accounting standard.

SFAS 143 requires companies to record a liability relating to the retirement of tangible long-lived assets. When the liability is initially recorded, a company increases the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. We adopted SFAS 143 on July 1, 2002 and recorded an asset retirement obligation of $194,866 related to our legal obligation to plug and abandon its oil and gas wells. We determined that the asset retirement obligation as of July 1, 2001 would not be materially different than the liability recorded on July 1, 2002. We consider that the cumulative effect of initially applying SFAS 143 is not material to the Consolidated Statement of Operations.

SFAS 144 addresses the financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS 144 supersedes SFAS 121 but retains its fundamental provisions for the (a) recognition and measurement of impairment of long-lived assets to be held and used and (b) measurement of long-lived assets to be disposed of by sale. SFAS 144 also supersedes the accounting and reporting portions of APB Opinion No. 30 for segments of a business to be disposed of but retains the requirements to report discontinued operations separately from continuing operations and extends that reporting to a component of an entity that either has been disposed of or is classified as “held for sale”. This standard is effective for fiscal years beginning after December 15, 2001. The adoption of SFAS 144 was not significant to our financial statements.

SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)”. This standard is effective for exit or disposal activities that are initiated after March 31, 2003, with early application encouraged. We do not anticipate the adoption of SFAS 146 will be significant to our financial statements.

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,
	2003			2002		Change		2003			2002		Change
Natural gas and oil sales	$	10,061,351		$	5,919,715	70	%	$	24,793,109		$	15,908,607	56	%
Gain (loss) from hedging activities	$	(5,230,672	)	$	90,789	*		$	(5,416,998	)	$	4,145,216	*

Production:
Natural gas (thousand cubic feet per day)		14,693			23,551	-38	%		16,943			18,820	-10	%
Oil and condensate (barrels per day)		342			640	-47	%		392			499	-21	%

Average sales price:
Natural gas (per thousand cubic feet)	$	6.84		$	2.53	170	%	$	4.69		$	2.70	74	%
Oil and condensate (per barrel)	$	33.22		$	18.30	82	%	$	27.96		$	20.55	36	%

Operating expenses	$	1,448,367		$	833,874	74	%	$	4,179,166		$	2,525,620	65	%
Exploration expenses	$	3,588,654		$	—	*		$	15,496,798		$	2,522,836	*
Depreciation, depletion and amortization	$	1,942,144		$	2,931,618	-34	%	$	6,518,654		$	6,044,823	8	%
General and administrative expenses	$	391,483		$	525,235	-25	%	$	1,464,576		$	1,331,146	10	%
Interest expense	$	177,860		$	87,882	102	%	$	531,763		$	97,244	*
Interest income	$	6,498		$	34,222	-81	%	$	27,663		$	169,156	-84	%
Gain on sale of assets and other	$	—		$	254,619	*		$	36,150		$	373,539	-90	%

Not meaningful

Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002

Natural Gas and Oil Sales. We reported natural gas and oil sales of approximately $10.1 million for the three months ended March 31, 2003, up $4.2 million, or 70%, from approximately $5.9 million reported for the three months ended March 31, 2002. This increase was attributable to substantial increases in the prices received for natural gas and oil production that were partially offset by a decrease in natural gas and oil production.

Natural Gas and Oil Production and Average Sales Prices. For the three months ended March 31, 2003, our net natural gas production decreased from approximately 23.6 million cubic feet of natural gas per day to approximately 14.7 million cubic feet of natural gas per day. Net oil production for the period decreased from 640 barrels of oil per day to 342 barrels of oil per day. This decrease primarily was due to the natural decline in production from our STEP properties. For the three months ended March 31, 2003, prices for natural gas and oil were $6.84 per Mcf and $33.22 per barrel, up substantially from $2.53 per Mcf and $18.30 per barrel for the three months ended March 31, 2002.

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. For the three months ended March 31, 2002, we recognized a gain from hedging activities of approximately $90,800 (see footnote 6 to Notes to Consolidated Financial Statements).

Operating Expenses. Operating expenses, including severance taxes, for the three months ended March 31, 2003 were approximately $1.4 million, an increase of approximately $614,500 from the $833,900 reported for the three months ended March 31, 2002. Of the $1.4 million reported for the three months ended March 31, 2003, approximately $727,900 was attributable to lease operating expense and ad valorem taxes, and approximately $720,400 was attributable to production and severance taxes. Operating expenses for the three months ended March 31, 2002 included approximately $398,900 of lease operating expenses and ad valorem taxes, and $435,000 of production and severance taxes. The increase in operating expenses for the three months ended March 31, 2003 was attributable to increases in severance taxes as a result of higher revenues, greater ad valorem taxes and operating expenses as a result of increased working interests in our STEP properties and to higher overall costs of operations. These cost increases were partially offset by lower production.

Exploration Expense. 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 $621,600 was the cost to shoot 3-D seismic in south Texas and $186,000 was related to two dry holes drilled in south Texas. For the three months ended March 31, 2002, we had no exploration expenses as a result of not incurring any seismic costs or dry hole expense during the period.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months ended March 31, 2003 was approximately $1.9 million. This primarily was attributable to depletion and amortization related to production at our STEP properties. For the three months ended March 31, 2002, we recorded approximately $2.9 million of depreciation, depletion and amortization. This primarily was attributable to depletion and amortization related to production from our STEP properties. The decrease in depreciation, depletion and amortization was primarily the result of lower production at our STEP properties.

General and Administrative Expenses. General and administrative expenses decreased approximately $133,700, from approximately $525,200 for the three months ended March 31, 2002 to approximately $391,500 for the three months ended March 31, 2003. Major components of general and administrative expense for the three months ended March 31, 2003 included approximately $108,600 in salaries and benefits, $93,100 in office administration, $66,800 in legal, accounting, engineering and other professional fees and $32,300 in insurance. Included in general and administrative expenses were $28,600 related to the cost of expensing stock options and $32,600 attributable to activities of Republic Exploration, Magnolia Offshore Exploration and Contango Offshore Exploration. The decrease in general and administrative expenses was primarily attributable to lower salaries, lower recorded amounts of franchise taxes and lower costs related to activities of Republic Exploration, Magnolia Offshore Exploration and Contango Offshore Exploration.

Interest Expense. We reported interest expense of approximately $177,900 for the three months ended March 31, 2003, up from the $87,900 reported for the three months ended March 31, 2002. This

increase primarily was attributable to increased borrowings under our bank line of credit resulting from our acquisition of proved properties completed during the period from January 2002 through July 2002.

Nine Months Ended March 31, 2003 Compared to Nine Months Ended March 31, 2002

Natural Gas and Oil Sales. We reported natural gas and oil sales of approximately $24.8 million for the nine months ended March 31, 2003, up from approximately $15.9 million reported for the nine months ended March 31, 2002. This increase was attributable to substantial increases in the prices received for natural gas and oil production that were partially offset by a decrease in natural gas and oil production.

Natural Gas and Oil Production and Average Sales Prices. For the nine months ended March 31, 2003, our net natural gas production decreased from approximately 18.8 million cubic feet of natural gas per day to approximately 16.9 million cubic feet of natural gas per day. Net oil production for the period was down from 499 barrels of oil per day to 392 barrels of oil per day. This decrease primarily was due to the natural decline in production from our STEP properties. For the nine months ended March 31, 2003, prices for natural gas and oil were $4.69 per Mcf and $27.96 per barrel, up substantially from $2.70 per Mcf and $20.55 per barrel for the nine months ended March 31, 2002.

Gain (loss) from Hedging Activities. 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. For the nine months ended March 31, 2002, we recognized a gain from hedging activities of approximately $4.1 million. This gain consisted primarily of gains on settlements of swap derivative agreements (see footnote 6 to Notes to Consolidated Financial Statements).

Operating Expenses. Operating expenses, including severance taxes, for the nine months ended March 31, 2003 were approximately $4.2 million, an increase of approximately $1.7 million from the $2.5 million reported for the nine months ended March 31, 2002. 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. Operating expenses for the nine months ended March 31, 2002 included approximately $1.4 million of lease operating expenses and approximately $1.1 million of production and severance taxes. The increase in operating expenses for the nine months ended March 31, 2003 was attributable to increases in severance taxes as a result of higher revenues, greater ad valorem taxes and lease operating expenses as a result of increased working interests in our STEP properties and to higher overall costs of operations. These cost increases were partially offset by lower production.

Exploration Expense. 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 $587,400 was related to dry hole costs in south Texas. For the nine months ended March 31, 2002, we reported approximately $2.5 million of exploration expenses. This amount primarily was attributable to the expensing of $2.2 million in dry holes drilled on our STEP properties and $279,500 of seismic costs attributable to data offshore in the Gulf of Mexico.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the nine months ended March 31, 2003 was approximately $6.5 million. This was attributable primarily to depletion and amortization related to production at our STEP properties. For the nine months ended March 31, 2002, we recorded approximately $6.0 million of depreciation, depletion and amortization. This also was attributable primarily to depletion and amortization related to production from our STEP properties. The increase in depreciation, depletion and amortization was attributable to increased costs of our producing properties stemming from our acquisition of STEP producing properties.

General and Administrative Expenses. General and administrative expenses increased from approximately $1.3 million for the nine months ended March 31, 2002 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, 2003 included approximately $307,700 in salaries and benefits, $211,600 in office administration, $554,800 in legal, accounting, engineering and other professional fees and $97,200 in insurance. Included in legal, accounting, engineering and other professional fees was a one-time charge of approximately $235,200 related to a proposed sale and corporate restructuring of our STEP properties. We are no longer considering the sale of these properties. Also included in general and administrative expenses was approximately $81,600 related to the cost of expensing stock options and $121,700 attributable to activities of Republic Exploration, Magnolia Offshore Exploration and Contango Offshore Exploration. The increase in general and administrative expenses was primarily due to increases in legal expenses related to the proposed sale and corporate restructuring of our STEP properties and the cost of expensing stock options, which was offset by lower salaries, lower recorded amounts of franchise taxes and lower costs related to activities of Republic Exploration, Magnolia Offshore Exploration and Contango Offshore Exploration.

Interest Expense. We reported interest expense of approximately $531,800 for the nine months ended March 31, 2003, up from the $97,200 reported for the nine months ended March 31, 2002. This increase was attributable to a higher average level of borrowings under our bank line of credit primarily resulting from our acquisition of proved properties completed during the period from January 2002 through July 2002. We had no bank borrowings prior to January 1, 2002.

Gain on Sale of Assets and Other. We reported a gain of $36,150 for the nine months ended March 31, 2003. This gain resulted from the early cash settlement with a counterparty of hedging contracts. For the nine months ended March 31, 2002, we reported a gain of approximately $373,500. This gain was attributable to lease sales of approximately $254,600 by Republic Exploration during the quarter ended March 31, 2002 and the balance was attributable to the sale of certain partnership interests and properties located in Colorado and Ft. Bend Counties, Texas earlier in the fiscal year.

Production, Prices, Operating Expenses, EBITDAX and Other

The following table presents information regarding production volumes, average sales prices received and average production costs and other meaningful information associated with our sales of natural gas and oil for the periods indicated.

	Three Months Ended March 31,				Nine Months Ended March 31,
	2003		2002		2003		2002
Production:
Natural gas (thousand cubic feet)		1,322,400		2,119,569		4,642,314		5,137,800
Oil and condensate (barrels)		30,744		57,616		107,389		136,200
Total (thousand cubic feet equivalent)		1,506,864		2,465,265		5,286,648		5,955,000

Natural gas (thousand cubic feet per day)		14,693		23,551		16,943		18,820
Oil and condensate (barrels per day)		342		640		392		499
Total (thousand cubic feet equivalent per day)		16,745		27,391		19,295		21,814

Average sales price:
Natural gas (per thousand cubic feet)	$	6.84	$	2.53	$	4.69	$	2.70
Oil and condensate (per barrel)	$	33.22	$	18.30	$	27.96	$	20.55
Total (per thousand cubic feet equivalent)	$	6.67	$	2.65	$	4.69	$	2.78

Operating expenses (per thousand cubic feet equivalent):
Production and severance taxes	$	0.48	$	0.18	$	0.33	$	0.19
Lease operating expense		0.48		0.16		0.46		0.23

Total operating expenses	$	0.96	$	0.34	$	0.79	$	0.42

Other expenses (per thousand cubic feet equivalent):
Depreciation, depletion and amortization of natural gas and oil properties	$	1.25	$	1.18	$	1.21	$	1.00
General and administrative expense	$	0.26	$	0.21	$	0.28	$	0.22
EBITDAX(1)	$	2,990,829	$	4,906,014	$	13,768,519	$	16,570,596

(1)

EBITDAX represents earnings before interest, income taxes, depreciation, depletion and amortization, exploration expenditures, including gain (loss) from hedging activities. 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 the 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,
	2003			2002		2003			2002
Income (loss) from operations	$	(2,539,969	)	$	1,719,777	$	(8,283,083	)	$	7,629,398
Depreciation, depletion and amortization		1,942,144			2,931,618		6,518,654			6,044,823
Exploration expenses		3,588,654			—		15,496,798			2,522,836
Gain on sale of assets and other		—			254,619		36,150			373,539

EBITDAX	$	2,990,829		$	4,906,014	$	13,768,519		$	16,570,596

Capital Resources and Liquidity

During the fiscal year ended June 30, 2002, we repurchased approximately 2.6 million shares of our common stock for approximately $6.2 million and increased our ownership interest in our STEP properties in four separate transactions at a total cost of approximately $23.4 million. In July 2002, we further increased our ownership in our STEP properties at a cost of approximately $2.6 million. Additionally, over the past two and one-half years, we have invested over $16.6 million to acquire, shoot and reprocess seismic data both onshore in south Texas and in the Gulf of Mexico. These expenditures, together with our exploration drilling costs and our investment in Freeport LNG, have been funded with cash on hand, internally generated cash flow and borrowings under our credit facility.

Our current levels of production are approximately 16.0 million cubic feet of natural gas and 300 barrels of oil per day. At anticipated production levels and current commodity price levels, we expect to have EBITDAX of approximately $2.0 million per month through calendar year end 2003. Lower prices for natural gas and oil, unanticipated declines in production, operational problems or other unforeseen circumstances could prevent us from realizing this level of EBITDAX.

EBITDAX for the nine months ended March 31, 2003 was approximately $13.8 million, down from EBITDAX for the nine months ended March 31, 2002 of approximately $16.6 million. EBITDAX for the three months ended March 31, 2003 was approximately $3.0 million, down from approximately $4.9 million from the three months ended March 31, 2002. The reduction in EBITDAX for the three and nine month periods was due, in large part, to the hedging losses recognized during the reporting periods. For a summary of derivative positions still open see “Quantitative and Qualitative Disclosures about Market Risk—Hedging Activities” below. Given our view that natural gas prices are likely to continue to stay strong, together with the potential for significant hedging losses when NYMEX natural gas prices can spike $5.00 in just two days as they did in late February, our current policy is to hedge only through the purchase of puts.

We are continuing our south Texas exploration efforts and have participated in two 3-D seismic shoots on acreage nearby our current STEP production. The cost of our 47.5% working interest participation in these two shoots is estimated to be approximately $3.0 million. Based on the seismic data from the first shoot, we have drilled nine wells since January 2003, seven of which were successful, and expect to drill two additional wells prior to June 30, 2003.

We are continuing our evaluation of this first seismic shoot. We expect to have the data from our second shoot available by late summer 2003. Over the remainder of this fiscal year which ends June 30,

2003, we expect to spend an additional $2.5 to $5.0 million on new south Texas and Gulf Coast drilling and acquisitions. In addition to exploration expenditures, we will commence in June 2003 paying a total of approximately$1.2 million as additional consideration for our 10% interest in Freeport LNG in twelve consecutive $100,000 monthly payments. For the remainder of calendar year 2003, we anticipate exploration expenditures of $5.0 to $15.0 million.

At May 12, 2003 we had approximately $256,000 in cash on hand, $20.2 million borrowed under our credit facility and $4.0 million of funds available under our credit facility.

We believe that our cash on hand, our anticipated cash flow from operations and funds available under our credit facility will be adequate to fund a capital budget for fiscal year 2004 of approximately $15.0 to $20.0 million. The Company may need to seek additional equity or other financing alternatives to fund acquisitions, pursue an expanded exploration program or to take advantage of other opportunities that may become available. In addition, we may from time-to-time as part of our business strategy sell some or a substantial portion of our assets as a means of raising capital to further our exploration activities. The availability of such funds and our ability to sell assets on a favorable basis 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 that matures in June 2004. The hydrocarbon borrowing base as of March 31, 2003 was $25.5 million and reduces by $670,000 per month the first day of each month. Borrowings under the credit facility 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 under the credit facility. 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, 2003, approximately $23.5 million was outstanding under the credit facility, and we were in compliance with all financial covenants and ratios. As of May 12, 2003, $20.2 million was outstanding under the credit facility, and we had $4.0 million of loan availability.

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, 2003, 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, 2003 was determined by the March 31, 2003 prices of $5.04 per MMbtu for natural gas at the Houston Ship Channel and $31.04 per barrel of oil at West Texas Intermediate Posting, in each case before adjusting for basis and transportation costs. Our reserves are 90% natural gas.

	Proved Developed Producing Reserves as of March 31, 2003
Natural gas (MMcf)		22,058
Oil and condensate (Bbls)		428,527
Total proved reserves (MMcfe)		24,629

Pre-tax net present value	$	72,619,430

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.

Quantitative and Qualitative Disclosures about Market Risk

Commodity Risk. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil. Prices received for natural gas and oil are volatile and unpredictable and are beyond our control. These prices affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Also, the amount we can borrow under our credit facility is subject to periodic redetermination based in part on changing expectations of future prices of natural gas and oil. For the nine months ended March 31, 2003, a 10% fluctuation in the prices received for natural gas and oil production would have had an approximate $2.5 million impact on our revenues.

Hedging Activities. Commodity derivative contracts generally entail the following risks, depending on the terms of the contract: (i) a significant increase or decrease in natural gas prices could lead to significant losses, (ii) gain from otherwise favorable price movements may be limited and (iii) counterparties may be unable to satisfy their financial obligations. Our experience with commodity derivative contracts has been mixed. For the nine months ended March 31, 2002, we reported a gain of approximately $4.1 million from hedging activities. For the nine months ended March 31, 2003, we reported a loss of $5.4 million from hedging activities.

These derivative contracts are placed with companies that we believe to be of high credit quality and minimal credit risk. As of May 12, 2003, we had approximately 50% of our projected June through October 2003 natural gas production hedged. None of our oil production is hedged. The following table provides our pricing and notional volumes on open commodity derivative contracts as of May 12, 2003

Contract Description	Term	Strike Price(1)		Quantity(1)
Natural gas puts owned	06/2003 – 10/2003	$	4.50	10,000/day
Natural gas puts owned	11/2003 – 12/2003	$	4.00	10,000/day
Natural gas calls sold	06/2003 – 07/2003	$	5.25	5,000/day
Natural gas calls sold	06/2003 – 07/2003	$	5.50	3,000/day
Natural gas calls sold	08/2003 – 10/2003	$	6.00	8,000/day

(1)

Prices and quantities per MMbtu.

Because these open contracts are marked-to-market on a daily basis, we are exposed to wide swings in commodity prices and could be subject to significant hedging losses in the event of a significant increase in natural gas prices. Accordingly, the terms of the agreements with certain counter parties provide that if the mark-to-market loss to that counter party exceeds $1.0 million, we will have to provide collateral to cover the potential loss position.

Gains or losses on these hedging transactions are the difference between the contract price and settlement price reported by New York Mercantile Exchange (“NYMEX”). If the above contracts were to settle at the NYMEX settlement prices as of May 12, 2003, we would incur a hedging loss of approximately $385,000. If the above contracts were to settle at prices 10% above the NYMEX settlement prices as of May 12, 2003, we would incur a loss of approximately $1.1 million.

Given our view that natural gas prices are likely to continue to stay strong, together with the potential for significant hedging losses when NYMEX natural gas prices can spike $5.00 in just two days as they did in late February, our current policy is to hedge only through the purchase of puts.

Interest Rate Risk. The carrying value of our debt approximates fair value. At March 31, 2003, we had approximately $23.8 million of total indebtedness, $23.5 million of which was outstanding under our credit facility. The credit facility matures in June 2004 and bears 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. The average interest rate on long-term debt at March 31, 2003 was 3.28%. The result of a 10% fluctuation in short-term rates would have had an approximate $53,200 impact on interest expense for the nine months ended March 31, 2003.

Item 3. Controls and Procedures

Kenneth R. Peak, our Chief Executive Officer and Chief Financial Officer, has evaluated our disclosure controls and procedures within 90 days of the filing of this report. These controls and procedures are designed to ensure that all of the information required to be disclosed by us in our periodic reports filed with the Securities and Exchange Commission (the “Commission”) is recorded, processed, summarized and reported within the time periods specified by the Commission and that the information is communicated to the Chief Executive Officer and Chief Financial Officer on a timely basis. Based on his evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were suitable and effective.

Subsequent to the date of his evaluation, there have been no significant changes in our internal controls or in other factors that could significantly affect the internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

None.

Item 2. Changes in Securities and Use of Proceeds

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-QSB. 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.(8)

3.2		Bylaws of Contango Oil & Gas Company, a Delaware corporation.(8)

3.3		Agreement of Plan of Merger of Contango Oil & Gas Company, a Delaware corporation, and Contango Oil & Gas Company, a Nevada corporation.(8)

3.4		Amendment to the Certificate of Incorporation of Contango Oil & Gas Company, a Delaware corporation.(18)

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

4.2		Certificate of Designations, Preferences and Relative Rights and Limitations for Series A Senior Convertible Cumulative Preferred Stock of Contango Oil & Gas Company, a Delaware corporation.(8)

4.3		Certificate of Designations, Preferences and Relative Rights and Limitations for Series B Senior Convertible Cumulative Preferred Stock of Contango Oil & Gas Company, a Delaware corporation.(8)

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.(15)

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 by and between Contango Oil & Gas Company and the Southern Ute Indian Tribe doing business as the Southern Ute Indian Tribe Growth Fund, dated June 8, 2000.(4)

10.6		Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Trust Company of the West.(5)

10.7		Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and the Southern Ute Indian Tribe doing business as the Southern Ute Indian Tribe Growth Fund.(5)

10.8		Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Fairfield Industries Incorporated.(5)

10.9		Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Juneau Exploration Company, L.L.C.(5)

10.10		Amendment dated August 14, 2000 to agreement between Contango Oil & Gas Company and Juneau Exploration Company, LLC. dated effective as of September 1, 1999.(6)

10.11		Securities Purchase Agreement dated September 27, 2000 by and between Contango Oil & Gas Company and Aquila Energy Capital Corporation.(7)

10.12		Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001.(9)


10.13		First Amendment dated as of January 8, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001.(10)

10.14		Asset Purchase Agreement by and among Juneau Exploration, L.P. and Contango Oil & Gas Company dated January 4, 2002.(10)

10.15		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.(11)

10.16		Asset Purchase Agreement by and among the Southern Ute Indian Tribe doing business as Red Willow Production Company and Contango Oil & Gas Company dated January 28, 2002.(12)

10.17		Securities Repurchase Agreement by and among the Southern Ute Indian Tribe doing business as Red Willow Production Company and Southern Ute Indian Tribe Growth Fund and Contango Oil & Gas Company dated March 28, 2002.(14)

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

10.19		Waiver dated as of March 25, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001.(13)

10.20		Option Purchase Agreement between Contango Oil & Gas Company and Cheniere Energy, Inc. dated June 4, 2002.(16)

10.21		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.(17)

10.22		Fourth Amendment dated as of September 9, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001.(17)

21.1		Subsidiaries of the Company.(17)

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

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

†

Filed herewith.

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.

Filed as an exhibit to the Company’s Form 10-QSB for the quarter ended September 30, 1999, as filed with the Securities and Exchange Commission on November 11, 1999.

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.

Filed as an exhibit to the Company’s report on Form 8-K, dated June 8, 2000, as filed with the Securities and Exchange Commission on June 14, 2000.

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.

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.

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.

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.

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.

10.

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.

11.

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.

12.

Filed as an exhibit to the Company’s report on Form 8-K, dated March 8, 2002, as filed with the Securities and Exchange Commission on March 15, 2002.

13.

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.

14.

Filed as an exhibit to the Company’s report on Form 8-K, dated March 28, 2002, as filed with the Securities and Exchange Commission on April 3, 2002.

15.

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.

16.

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.

17.

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.

18.

Filed as an exhibit to the Company’s report filed on Form 10-QSB for the quarter ended September 30, 2002, dated November 14, 2002, as filed with the Securities and Exchange Commission.

(b) Reports on Form 8-K:

On February 11, 2003, we filed a report on Form 8-K reporting earnings for the quarter ended December 31, 2002.

On March 3, 2003, we filed a report on Form 8-K reporting that we had exercised our option with Cheniere Energy Inc. to acquire a 10% interest in Freeport LNG Development LP, a limited partnership formed to develop a LNG receiving terminal in Freeport, Texas.

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 13, 2003	By:	/s/ KENNETH R. PEAK
		Kenneth R. Peak
		Chairman and Chief Executive Officer
		(Principal Executive and Financial Officer)

Date: May 13, 2003	By:	/s/ LESIA BAUTINA
		Lesia Bautina
		Vice President and Controller
		(Principal Accounting Officer)

SECTION 302 CERTIFICATION

PRINCIPAL EXECUTIVE OFFICER AND PRINCIPAL FINANCIAL OFFICER

I, Kenneth R. Peak, certify that:

I have reviewed this quarterly report on Form 10-QSB of Contango Oil & Gas Company;

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

As the registrant’s sole certifying officer, I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and I have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this quarterly report is being prepared;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report my conclusions about the effectiveness of the disclosure controls and procedures based on my evaluation as of the Evaluation Date;

I have disclosed, based on my most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of my most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 13, 2003

/s/ KENNETH R. PEAK

Kenneth R. Peak

Chairman, Chief Executive Officer

and Chief Financial Officer

Exhibit Number		Description

3.1		Certificate of Incorporation of Contango Oil & Gas Company, a Delaware corporation.

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

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

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

4.1		Facsimile of common stock certificate of the Company.

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

4.3		Certificate of Designations, Preferences and Relative Rights and Limitations for Series B Senior Convertible Cumulative Preferred Stock of Contango Oil & Gas Company, a Delaware corporation.

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

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

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

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

10.5		Securities Purchase Agreement by and between Contango Oil & Gas Company and the Southern Ute Indian Tribe doing business as the Southern Ute Indian Tribe Growth Fund, dated June 8, 2000.

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

10.7		Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and the Southern Ute Indian Tribe doing business as the Southern Ute Indian Tribe Growth Fund.

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

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

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

10.11		Securities Purchase Agreement dated September 27, 2000 by and between Contango Oil & Gas Company and Aquila Energy Capital Corporation.

10.12		Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001.

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

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

10.15		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.


10.16		Asset Purchase Agreement by and among the Southern Ute Indian Tribe doing business as Red Willow Production Company and Contango Oil & Gas Company dated January 28, 2002.

10.17		Securities Repurchase Agreement by and among the Southern Ute Indian Tribe doing business as Red Willow Production Company and Southern Ute Indian Tribe Growth Fund and Contango Oil & Gas Company dated March 28, 2002.

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

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

10.20		Option Purchase Agreement between Contango Oil & Gas Company and Cheniere Energy, Inc. dated June 4, 2002.

10.21		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.

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

21.1		Subsidiaries of the Company.

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

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