Edgar Filing: CONTANGO OIL & GAS CO

Form 10-KSB

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-KSB

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended June 30, 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)

Securities registered pursuant to Section 12(b) of the Act:

Common Stock, Par Value $0.04

American Stock Exchange

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 ¨

Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B is not contained in this form, or will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-KSB or any amendment to this Form 10-KSB ¨

Revenues from operations for the fiscal year ended June 30, 2003 were $28,210,168.

The aggregate market value of the voting common stock held by non-affiliates based on the closing price at September 12, 2003, was $22,932,639. As of September 12, 2003, there were 9,301,692 shares of the issuer’s common stock outstanding.

Documents Incorporated by Reference

Items 9, 10, 11 (other than with respect to Item 201(d) of Regulation S-B) and 12 of Part III have been omitted from this report since registrant will file with the Securities and Exchange Commission, not later than 120 days after the close of its fiscal year, a definitive proxy statement, pursuant to Regulation 14A. The information required by Items 9, 10, 11 (other than with respect to Item 201(d) of Regulation S-B) and 12 of this report, which will appear in the definitive proxy statement, is incorporated by reference into this Form 10-KSB.

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

ANNUAL REPORT ON FORM 10-KSB

FOR THE FISCAL ENDED JUNE 30, 2003

TABLE OF CONTENTS

		Page

PART I

Item 1.	Business

	Overview	1

	Our Strategy	1

	Exploration Alliance with JEX and Alta Resources	2

	Onshore Exploration and Properties	3

	Offshore Exploration Joint Ventures	4

	Offshore Properties	6

	Freeport LNG Development, L.P.	7

	Natural Gas and Oil Prices	7

	Marketing	8

	Governmental Regulations	8

	Employees	12

	Directors and Executive Officers	13

	Corporate Offices	15

	Code of Ethics	15

	Risk Factors	15

Item 2.	Description of Properties

	Production, Prices, Operating Expenses, EBITDAX and Other	24

	Development, Exploration and Acquisition Capital Expenditures	25

	Drilling Activity	25

	Exploration and Development Acreage	26

	Productive Wells	26

	Natural Gas and Oil Reserves	26

Item 3.	Legal Proceedings	27

Item 4.	Submission of Matters to a Vote of Security Holders	27

PART II

Item 5.	Market for Common Equity and Related Stockholder Matters	28

Item 6.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

	Introduction	29

	Critical Accounting Policies	29

	MD&A Summary Data	32

	Year Ended June 30, 2003 Compared to Year Ended June 30, 2002	32

	Capital Resources and Liquidity	34

	Credit Facility	36

	Quantitative and Qualitative Disclosure About Market Risk	37

Item 7.	Financial Statements and Supplementary Data	38

Item 8.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	38

Item 8a	Controls and Procedures	38

PART III

Item 9.	Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act	38

Item 10.	Executive Compensation	38

Item 11.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	39

Item 12.	Certain Relationships and Related Transactions	39

Item 13.	Exhibits and Reports on Form 8-K	39

Cautionary Statement About Forward-Looking Statements

Some of the statements made in this Form 10-KSB may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, 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

•

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:

•

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

•

Availability of capital and the ability to repay indebtedness when due

•

Ability to raise capital to fund capital expenditures

•

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

•

Natural gas and oil price volatility

•

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

•

Operating hazards attendant to the natural gas and oil business

•

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

•

Potential mechanical failure or under-performance of significant wells or pipeline mishaps

•

Climatic conditions

•

Availability and cost of material and equipment

•

Delays in anticipated start-up dates

•

Actions or inactions of third-party operators of our properties

•

Commodity price movements adversely affecting our hedge position

•

Ability to find and retain skilled personnel

•

Strength and financial resources of competitors

•

Regulatory developments

•

Environmental risks

•

General economic conditions

When you consider these forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this Form 10-KSB. You should not unduly rely on these forward-looking statements in this report, as they speak only as of the date of this report. Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events. See the information under the heading “Risk Factors” on page 15 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.

iii

All references in this Form 10-KSB to the “company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas Company and Subsidiaries. Unless otherwise noted, all information in this Form 10-KSB 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.

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

PART I

Item 1.

Business

Overview

We are an independent natural gas and oil company engaged in the exploration, production and acquisition of natural gas and oil in the United States. Our primary source of production is currently in south Texas. While our south Texas properties account for nearly all of our production, we also have interests in producing properties located offshore in the Gulf of Mexico and hold a 10% limited partnership interest in a proposed LNG terminal in Freeport, Texas.

As of June 30, 2003, we owned approximately 23.6 Bcfe of total proved reserves, compared to 27.9 Bcfe as of June 30, 2002. As of June 30, 2003 and 2002, approximately 97% and 99% of total proved reserves, respectively, were classified as proved developed producing. The pre-tax net present value of our total proved reserves prepared in accordance with the Securities and Exchange Commission (the “SEC”) guidelines as of June 30, 2003 was approximately $69.6 million, compared to $53.3 million as of June 30, 2002.

Total revenues and EBITDAX for the year ended June 30, 2003 were $28.2 million and $20.9 million, respectively. For the year ended June 30, 2002, total revenues and EBITDAX were $28.9 million and $22.5 million, respectively. We define EBITDAX as earnings before interest, income taxes, depreciation, depletion and amortization, impairment expense and expensed exploration expenditures, including gains or losses from hedging. See Item 2. Description of Properties, “Production, Prices, Operating Expenses, EBITDAX and Other” for more information about the calculation of EBITDAX and its uses. Average net daily production for the year ended June 30, 2003 was 16.5 MMcf of natural gas and 380 barrels of oil per day, compared to 19.1 MMcf of natural gas and 510 barrels of oil per day for the year ended June 30, 2002.

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 two alliance partners, Juneau Exploration Company, LP (“JEX”) and Alta Resources, LLC (“Alta Resources”), perform our onshore prospect generation and evaluation functions, while JEX performs all of our offshore prospect generation and evaluation functions. JEX’s proven group of explorationists has demonstrated its ability to find reserves both onshore and offshore in the Gulf of Mexico. Our current south Texas producing properties were discovered by JEX. Alta Resources is a private company formed for the purpose of assembling domestic, onshore natural gas and oil projects. Alta Resources’ geoscientists have been directly responsible for significant natural gas and oil discoveries in Texas and Mississippi and have additional expertise in Louisiana and the Rockies. Our principal exploration strategy is to fund exploration prospects generated by JEX and Alta Resources.

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

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. 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 our 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.

Structuring incentives to drive behavior. We believe that equity ownership aligns the interests of our partners, employees, and stockholders. Our directors and executive officers beneficially own approximately 25% of our common stock. In addition, the agreements with our alliance partners require them to co-invest on prospects that they recommend to us.

Exploration Alliance with JEX and Alta Resources

Alliance with JEX. Under Contango Oil & Gas Company’s agreement with JEX, JEX evaluates natural gas and oil prospects and recommends exploration prospect and proved property acquisition investment opportunities to us. In exchange, we have committed, within various parameters, to invest along with JEX up to 95% of the available working interest in the recommended prospects and property acquisitions. 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 June 30, 2003, 285,834 options remain vested and unexercised.

In connection with the formation of Republic Exploration, we granted to JEX warrants to purchase 125,000 shares of our common stock, all of which are vested. Under the JEX agreement, JEX brings onshore prospects directly to Contango. Offshore prospects are typically generated by our affiliated companies. See “Offshore Exploration Joint Ventures” below.

If JEX recommends any prospects to Contango, we pay the lease and seismic costs, and JEX generally pays the remaining costs of generating and preparing a prospect to drill ready status. When drilling begins on a prospect, we are obligated to assign to JEX and the JEX geoscientists an overriding royalty interest equal to 3 1/3% of our working interest in the prospect. In addition, when our revenues from prospects we invest in under the agreement during a calendar year, net of taxes, royalties and other expenses equals our capital expenditure related to the acquisition and development of the prospects on a well-by-well basis, JEX is entitled to an assignment or automatic reversion of 25% of our working interest in the well. With respect to reserve acquisitions, we have the right, but not the obligation, to purchase up to 95% of the interests available to JEX in proved natural gas and oil reserves.

We may terminate the agreement upon 30 days written notice, and JEX may terminate the agreement upon 180 days notice. If we are in default under the agreement, however, JEX may terminate the agreement upon 30 days written notice. John B. Juneau, who beneficially owns more than 10% of our common stock, is the sole manager of the general partner of JEX.

Alliance with Alta Resources. In July 2003, Contango and Alta Resources entered into an agreement with Seitel Data Ltd. for a 3-D seismic shoot covering 39 square miles in southern Duval County, Texas. The estimated cost to Contango is approximately $1.7 million. The seismic shoot is scheduled for completion by November 2003, and processing, evaluation and prospect identification is expected by January 2004. As part of the participation agreement between Contango and Alta Resources, Contango will receive a 42.5% working interest (an approximate 32% net revenue interest) in approximately 9,000 acres of natural gas and oil leases owned by Alta Resources in Duval County, Texas. These leases are directly on trend with nearby Queen City discoveries, including our Queen City production located to the south. We will have the right to participate in any wells drilled on identified prospects. On each prospect drilled, Alta Resources will receive an overriding royalty interest ranging from 1.0% to 3.0% of our working interest depending on the net revenue interest in the prospect. When drilling begins on a prospect, we will bear 50% of the drilling costs through first production and will have a 42.5% working interest (an approximate 32% net revenue interest) in producing wells.

Onshore Exploration and Properties

Our first significant onshore drilling program was on properties located on our South Texas Exploration Program (“STEP”). The first STEP wells were discovered by JEX in the summer of 2000 after a review of 3-D seismic data covering approximately 100 square miles. JEX entered into a joint exploration agreement with the mineral owner, who acted as the operator. From May 2000 through February 2002, we drilled 41 exploratory wells resulting in 31 commercial successes.

Since completing the drilling on our STEP properties, we have participated in two 3-D seismic shoots covering approximately 180 square miles south of our STEP production. The first covered approximately 80 square miles at a cost of approximately $1.7 million. Based on the evaluation of this 3-D seismic shoot, we drilled 15 wells between January and June 30, 2003.

In September 2003 we completed the sale of some non-core reserves in Brooks County, Texas for $5.0 million. Proved reserves were 1.5 Bcfe and accounted for approximately $5.0 million of the Company’s discounted present value at 10% per annum as of June 30, 2003. The effective sales date was July 1, 2003. Our current production rate following the sale of these properties is approximately 16,000 MMbtue per day.

Outlook. On our original STEP properties, we recently started the drilling of a Queen City development well.

We recently completed our second 3-D seismic shoot in Jim Hogg and Starr Counties, Texas, covering approximately 100 square miles at a cost of approximately $2.2 million. The processing and evaluation of this data is now complete, and we expect to drill an initial Queen City well in October 2003. If this play develops, we would expect to drill another five to seven wells with drilling expenditures in the $3.0 to $4.0 million range.

Contango and Alta Resources are now conducting a 3-D seismic shoot covering approximately 40 square miles in southern Duval County, Texas that we expect to complete by November 1, 2003. The net cost to us will be approximately $1.7 million. If any prospects are identified, we would anticipate the start of drilling activities in the December 2003 through January 2004 timeframe. Additionally, we are going to participate with Alta Resources in the drilling of a Queen City exploratory well in Jim Hogg County, Texas in October 2003.

Separately, Contango is participating with an approximately 7.1% working interest in a 15,500 foot Wilcox test in Goliad County, Texas. Contango’s dry hole cost in this well is approximately $330,000.

Offshore Exploration Joint Ventures

Contango. Contango directly and through affiliated companies conducts exploration activities in the Gulf of Mexico. To date, Contango has acquired a direct interest in a total of seven offshore leases. Current production is approximately 20.0 MMcf of natural gas and 1,500 barrels of oil per day. Based on anticipated production rates and current prices, we expect Contango and its affiliates will earn their after payout working interests during the first half of 2004, and we expect to receive approximately $400,000 per month cash flow after payout. See “Offshore Operations and Properties” below for additional information on Contango’s offshore properties.

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, 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. Since its formation in August 2000, Contango has invested approximately $6.7 million in cash in Republic Exploration for a 33.3% ownership interest. 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. See “Offshore Operations and Properties” below for more information on Republic Exploration’s offshore properties.

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

Contango Offshore Exploration LLC. Contango purchased a 66.7% interest in Contango Offshore Exploration in September 2002. JEX is the only other member and acts as the managing member. Contango Offshore Exploration’s activities will be focused on identifying and purchasing prospects in the Gulf of Mexico and selling them to third parties, retaining a reversionary interest. To date, Contango Offshore Exploration has invested approximately $6.1 million to acquire and reprocess 2,294 blocks of 3-D seismic data and to acquire leases in the Gulf of Mexico. Contango Offshore Exploration has acquired a total of four leases, all of which are available for farmout. All leases will be subject to a 3.3% overriding royalty interest in favor of the JEX exploration team. See “Offshore Operations and Properties” below for additional information on Contango Offshore Exploration’s properties.

Outlook. Two wells have been successfully drilled on Eugene Island 110, a lease block farmed out by Contango and Republic Exploration. Production commenced during the summer of 2003 and is currently averaging approximately 20.0 MMcf of natural gas and 1,500 barrels of oil per day. Based on current production rates and prices, we expect Contango and Republic Exploration will earn their after payout working interests during the first half of 2004, and we expect to receive approximately $400,000 per month cash flow after payout. Contango, Republic Exploration and Magnolia Offshore Exploration have recently farmed out three “deep shelf” lease blocks. Magnolia Offshore Exploration’s lease block, Viosca Knoll 211, is currently drilling. The two lease blocks farmed out by Contango and Republic Exploration, Eugene Island 113B and Vermillion 73, are expected to spud by year-end 2003.

In August 2003, Contango Offshore Exploration and Republic Exploration participated in the Gulf of Mexico Lease Sale #187. Republic Exploration was high bidder on one lease block, and Contango Offshore Exploration was apparent high bidder on four lease blocks. An apparent high bid gives the bidding party propriety in award of offered tracts, notwithstanding the fact that the Minerals Management Service may reject all bids for a given tract. The review process can take up to 90 days on some bids. Three of Contango Offshore Exploration’s lease blocks are located in the East Breaks area and are in deep water (1,600 to 2,500 feet). If awarded, they represent a new exploration region for Contango. As with our deep shelf exploration, our business plan is to farmout these prospects and retain only a reversionary working interest or an overriding royalty interest. Contango expects that Republic Exploration and Contango Offshore Exploration will participate in the Central Gulf of Mexico lease sale to be held in March 2004.

Offshore Properties

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

Area/Block	WI		NRI		Acquired	Status

Contango Oil & Gas Company:
Eugene Island 28	21.4	%	15.3	%	Mar-00	Producing; marginal well; sale pending
Brazos 436	13.6	%	10.8	%	Jul-00	Shut in; pending abandonment
Grand Isle 28	(2	)	(2	)	Apr-01	Shut in
East Cameron 107	33.8	%	27.0	%	May-01	Available for farm-out
Eugene Island 113B	(2	)	(2	)	May-01	Farmed out; expected to spud 4Q2003
Eugene Island 110	(2	)	(2	)	Jul-01	Well #1 and #2; producing

Republic Exploration (1):
High Island 25L, N/2NE	(3	)	(3	)	Jan-01	Producing
Grand Isle 28	(2	)	(2	)	Apr-01	Shut in
East Cameron 107	66.2	%	53.0	%	May-01	Available for farm-out
Eugene Island 113B	(2	)	(2	)	May-01	Farmed out; expected to spud 4Q2003
Eugene Island 110	(2	)	(2	)	Jul-01	Well #1 and #2; producing
West Delta 36	100.0	%	80.0	%	May-02	Available for farm-out
Vermilion 73	(3	)	(3	)	Jul-02	Farmed out; expected to spud 4Q2003
West Cameron 174	100.0	%	80.0	%	Jun-03	Available for farm-out
High Island 113	100.0	%	80.0	%	Sep-03	Available for farm-out

Magnolia Offshore Exploration (1):
Ship Shoal 155	100.0	%	80.0	%	May-02	Available for farm-out
Viosca Knoll 75	100.0	%	80.0	%	May-02	Available for farm-out
Viosca Knoll 211	(4	)	(4	)	Jul-02	Farmed out; drilling

Contango Offshore Exploration (1):
Vermillion 231	100.0	%	80.0	%	May-03	Available for farm-out
Viosca Knoll 167	100.0	%	80.0	%	May-03	Available for farm-out
Eugene Island 209	100.0	%	80.0	%	Jun-03	Available for farm-out
Viosca Knoll 161	100.0	%	80.0	%	Jun-03	Available for farm-out
High Island A16	—		—		—	Apparent high bidder in 08/20/03 MMS sale
East Breaks 283	—		—		—	Apparent high bidder in 08/20/03 MMS sale
East Breaks 369	—		—		—	Apparent high bidder in 08/20/03 MMS sale
East Breaks 370	—		—		—	Apparent high bidder in 08/20/03 MMS sale

(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, $1,050,000 of which has already been paid as of September 12, 2003. The balance is being paid in $100,000 monthly payments, with an additional $400,000 due upon receipt of Federal Energy Regulatory Commission (“FERC”) approval for the project. In March 2003, we announced that Freeport LNG had submitted a filing to the FERC for the construction of the LNG receiving terminal. A response from the FERC is not expected prior to the first quarter of 2004. In August 2003, we announced that Freeport LNG Development L.P. had signed a contract with Technip USA, a subsidiary of Technip, for the Front End Engineering Design that will lead to the finalization of the EPC (engineering, procurement and construction) contract for its proposed LNG receiving terminal. Assuming that FERC approval is received in early 2004, the construction phase is expected to commence during 2004, with the first LNG shipment being received in 2007.

Natural Gas and Oil Prices

Substantially all of our production is sold under various terms and arrangements at prevailing market prices. Our revenues, profitability and future growth depend significantly on natural gas and oil prices. Price decreases would adversely affect our revenues, profits and the value of our proved reserves. Historically, the prices received for natural gas and oil have fluctuated widely. Among the factors that can cause these fluctuations are:

•

The domestic and foreign supply of natural gas and oil

•

Overall economic conditions

•

The level of consumer product demand

•

Weather conditions

•

The price and availability of alternative fuels

•

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

•

The price of foreign imports

•

Domestic and foreign governmental regulations

•

Potential price controls

From time to time, we enter into hedging arrangements to reduce our exposure to decreases in the prices of natural gas and oil. Hedging arrangements expose us to risk of significant financial loss in some circumstances including circumstances where:

•

There is a change in the expected differential between the underlying price in the hedging agreement and actual prices received

•

Production is less than expected

•

Payments owed under derivative hedging contracts typically come due prior to receipt of the hedged months production revenue

•

The other party to the hedging contract defaults on its contract obligations

In addition, hedging arrangements limit the benefit we would receive from increases in the prices for natural gas and oil. We cannot assure you that the hedging transactions we enter into will adequately protect us from declines in the prices of natural gas and oil. On the other hand, we may choose not to engage in hedging transactions in the future. As a result, we may be more adversely

affected by changes in natural gas and oil prices than our competitors who engage in hedging transactions.

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

Our business has been and will continue to be affected by changes in natural gas and oil prices. No assurance can be given to the trend in, or level of, future natural gas and oil prices.

Marketing

Our production is marketed to third parties and is sold under daily or monthly pricing agreements based upon factors normally considered in the industry. We have not experienced any difficulties in marketing our natural gas and oil. The natural gas and oil industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual customers. The availability of a ready market for our natural gas and oil production depends on the proximity of reserves to, and the capacity of, natural gas and oil gathering systems, pipelines and trucking or terminal facilities. We deliver natural gas through gas gathering systems and gas pipelines that we do not own. Federal and state regulation of natural gas and oil production and transportation, tax and energy policies, changes in supply and demand and general economic conditions all could adversely affect our ability to produce and market our natural gas and oil. Most of our current production comes from wells drilled in south Texas. This production is being sold to a single purchaser. Any disruption of our marketing arrangements or financial difficulties with our purchaser, or alternative marketing sources, could have an adverse effect on our ability to market our natural gas and oil production. Additionally, if our purchaser suffered financial difficulties, we might not be able to collect receivables from the purchaser. However, we have the option to market our production of natural gas and oil to other alternative purchasers.

Governmental Regulations

We are subject to complex laws that can affect the cost, manner or feasibility of doing business. Exploration, development, production and sale of natural gas and oil are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:

•

Discharge permits for drilling operations

•

Drilling bonds

•

Reports concerning operations

•

The spacing of wells

•

Unitization and pooling of properties

•

Taxation

Under these laws, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties,

suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition and results of operations.

Federal regulation of sales and transportation of natural gas. Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated pursuant to several laws enacted by Congress and the regulations promulgated under these laws by the FERC. In the past, the federal government has regulated the prices at which gas could be sold. Congress removed all price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. Congress could, however, reenact price controls in the future.

Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the FERC that affect the economics of natural gas production, transportation and sales. In addition, the FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to the FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation.

The ultimate impact of the complex rules and regulations issued by the FERC since 1985 cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial and FERC final decisions. We cannot predict what further action the FERC will take on these matters. Some of the FERC’s more recent proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers and marketers with which we compete.

The Outer Continental Shelf Lands Act, or OCSLA, requires that all pipelines operating on or across the Outer Continental Shelf, or the Shelf, provide open-access, non-discriminatory service. Historically, the FERC has opted not to impose regulatory requirements under its OCSLA authority on gatherers and other entities outside the reach of its Natural Gas Act jurisdiction. However, the FERC has issued Order No. 639, requiring that virtually all non-proprietary pipeline transporters of natural gas on the Shelf report information on their affiliations, rates and conditions of service. These reporting requirements apply, in certain circumstances, to operators of production platforms and other facilities on the Shelf with respect to gas movements across such facilities. In a recent decision, the U.S. District Court for the District of Columbia permanently enjoined the FERC from enforcing Order No. 639, on the basis that the FERC did not possess the requisite rule-making authority under the OCSLA for issuing Order No. 639. The FERC’s appeal of the court’s decision is pending in the U.S. Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of this appeal, nor can we predict what further action the FERC will take with respect to this matter. In addition, the FERC retains authority under OCSLA to exercise jurisdiction over entities outside the reach of its Natural Gas Act jurisdiction if necessary to ensure non-discriminatory access to service on the Shelf. We do not believe that any FERC action taken under OCSLA will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers with which we compete.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

Federal regulation of sales and transportation of crude oil. Our sales of crude oil and condensate are currently not regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products are dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. Certain regulations implemented by the FERC in recent years could result in an increase in the cost of transportation service on certain petroleum products pipelines. However, we do not believe that these regulations affect us any differently than other natural gas producers.

Federal leases. Some of our operations are located on federal natural gas and oil leases, which are administered by the U.S. Department of Interior’s Mineral Management Service (“MMS”). These leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to OCSLA (which are subject to change by the MMS). For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency), lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the Shelf to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. To cover the various obligations of lessees on the Shelf, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial, and there is no assurance that bonds or other surety can be obtained in all cases. Under certain circumstances, the MMS may require that our operations on federal leases be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition, cash flows and results of operations.

The MMS has issued a final rule that governs the calculation of royalties and the valuation of crude oil produced from federal leases. This rule provides that the MMS will collect royalties based upon the market value of oil produced from federal leases. The lawfulness of the new rule has been challenged in federal court. We cannot predict what action the MMS will take on this matter. We believe that these rules will not have a material effect on our financial position, cash flows or results of operations.

State and local regulation of drilling and production. We own interests in properties located onshore Texas. We also own interests in properties in the state waters offshore Texas. Texas regulates drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilling and the plugging and abandonment of wells. Laws also govern a number of environmental and conservation matters, including the handling and disposing

of waste materials, the size of drilling and spacing units or proration units and the density of wells which may be drilled, unitization and pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells.

Environmental regulations. Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the obligation to perform investigatory or remedial activities or the imposition of injunctive relief. Environmental laws and regulations are complex, change frequently and have tended to become more stringent over time. Both onshore and offshore drilling in certain areas has been opposed by environmental groups and, in certain areas, has been restricted. To the extent laws are enacted or other governmental action is taken that prohibits or restricts onshore or offshore drilling or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and prospects could be adversely affected.

The Oil Pollution Act of 1990, or OPA, imposes regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from spills in U.S. waters. A “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns strict, joint and several liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation, or if the party fails to report a spill or to cooperate fully in the cleanup. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages for offshore facilities and up to $350 million for onshore facilities. Few defenses exist to the liability imposed by OPA. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party to administrative, civil or criminal enforcement actions.

OPA also requires operators in the Gulf of Mexico to demonstrate to the MMS that they possess available financial resources that are sufficient to pay for certain costs that may be incurred in responding to an oil spill. Under OPA and MMS regulations, responsible parties are required to demonstrate that they possess financial resources sufficient to pay for environmental cleanup and restoration costs of at least $10 million for an oil spill in state waters and at least $35 million for an oil spill in federal waters.

In addition to OPA, our discharges to waters of the U.S. are further limited by the federal Clean Water Act, or CWA, and analogous state laws. CWA prohibits any discharge into waters of the United States except in compliance with permits issued by federal and state governmental agencies. Failure to comply with CWA, including discharge limits on permits issued pursuant to CWA, may also result in administrative, civil or criminal enforcement actions. OPA and CWA also require the preparation of oil spill response plans.

OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Shelf. Specific design and operational standards may apply to vessels, rigs, platforms, vehicles and structures operating or located on the Shelf. Violations of lease conditions or regulations issued pursuant to OCSLA can result in substantial administrative,

civil and criminal penalties, as well as potential court injunctions curtailing operations and the cancellation of leases.

The Resource Conservation and Recovery Act, or RCRA, generally regulates the disposal of solid and hazardous wastes. Although RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy,” legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes”, which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could increase our operating costs, as well as those of the natural gas and oil industry in general. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.

The Comprehensive Environmental Response, Compensation, and Liability Act, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. Persons who are or were responsible for releases of hazardous substances under the Superfund law may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own or lease onshore properties that have been used for the exploration and production of natural gas and oil for a number of years. Some of these onshore properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and any wastes that may have been disposed or released on them may be subject to the Superfund law, RCRA and analogous state laws, and we potentially could be required to investigate and remediate such properties.

We believe that we are in substantial compliance with current applicable U.S. federal, state and local environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. There can be no assurance, however, that current regulatory requirements will not change, currently unforeseen environmental incidents will not occur or past non-compliance with environmental laws or regulations will not be discovered.

Employees

We currently have four employees, all of whom are full time. We use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, legal, environmental and tax services. We are dependent on our alliance partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. In addition, as a working interest owner in drilling wells and producing properties, we rely on outside operators and also utilize the services of independent contractors to perform field and on-site drilling and production operation services.

Directors and Executive Officers

The following table sets forth the names, ages and positions of our directors and executive officers:

Name	Age	Position
Kenneth R. Peak	58	Chairman, President, Chief Executive Officer, Chief Financial Officer, Secretary and Director
William H. Gibbons	60	Vice President and Treasurer
Lesia Bautina	32	Vice President and Controller
Jay D. Brehmer	38	Director
Michael P. Childers	42	Director
Joseph S. Compofelice	54	Director
Darrell W. Williams	60	Director

Kenneth R. Peak. Mr. Peak has been Chairman and CEO of Contango since its formation in September 1999. Prior to September 1999, Mr. Peak was President of Peak Enernomics, Incorporated, a company engaged in consulting activities to the oil and gas industry. Mr. Peak’s energy career began in 1973 as a commercial banker in First Chicago’s energy group. In 1980, Mr. Peak became Treasurer of Tosco Corporation and in 1982 Chief Financial Officer of Texas International Company (T.I.). Mr. Peak’s tenure included serving as President of TIPCO, the domestic operating subsidiary of T.I.’s oil and gas operations. Mr. Peak has also served as Chief Financial Officer of Forest Oil and as an investment banker with Howard Weil. Mr. Peak served as an officer in the U.S. Navy from 1968 to 1971. Mr. Peak received a BS in physics from Ohio University and a MBA from Columbia University. He currently serves as a director Patterson-UTI Energy, Inc.

William H. Gibbons. Mr. Gibbons joined Contango in February 2000 as Treasurer and was appointed Vice President and Treasurer in November 2000. His energy career began with Houston Oil & Minerals Corporation, where he was Treasurer from 1975 to 1981. From 1981 to 1983, he served as Vice President-Finance and Administration for Guardian Oil Company. From 1983 to 1986 and 1990 to 1998, Mr. Gibbons provided financial consulting services to domestic and international oil companies, including a five-year financing assignment with Walter International, Inc. (1991-1996). He also has served as Director of Acquisitions for Service Corporation International (1986-1990) and Treasurer of Packaged Ice, Inc. (1998-2000). Mr. Gibbons received a BA in Business Administration from Duke University and a MBA in Finance from Tulane University.

Lesia Bautina. Ms. Bautina Lesia joined Contango in November 2001 as Controller and was appointed Vice President and Controller in August 2002. Prior to joining Contango, Ms. Bautina worked as an auditor for Arthur Andersen LLP from 1997 to 2001. Her primary experience is accounting and financial reporting for exploration and production companies. Ms. Bautina received a degree in History from the University of Lvov in the Ukraine in 1990 and a BBA in Accounting in 1996 from Sam Houston State University, where she graduated with honors. Ms. Bautina is a Certified Public Accountant and Member of the Petroleum Accounting Society of Houston.

Jay D. Brehmer. Mr. Brehmer currently is managing director and a founder of Bullfrog Capital Partners, LLC, a mezzanine fund focused on investments in the oil and gas industry. From

May 1998 to until November 2002, Mr. Brehmer was responsible for structured-finance energy related transactions at Aquila Energy Capital Corporation. Prior to joining Aquila, Mr. Brehmer founded Capital Financial Services that provided mid-cap companies with strategic merger and acquisition advice coupled with prudent financial capitalization structures. His corporate finance industry experience also includes five years from 1990 until 1995 as Vice President of the investment banking subsidiary of Mutual of Omaha. He was responsible for the development and completion of all aspects of both private and public securities transactions. From 1985 until 1990, he was Vice President-Corporate Finance and Operations Manager for R. G. Dickinson & Company, a full service regional brokerage firm, where he created and managed the financial modeling of various public and private securities transactions. Mr. Brehmer holds a BBA from Drake University in Des Moines, Iowa.

Michael P. Childers. Mr. Childers is the President of the Engineering, Construction and Maintenance Division of The Shaw Group, Inc., where he also serves as the President of Stone & Webster. From July 2002 until March 2003, Mr. Childers was President of Entergy Asset Management, a wholly owned subsidiary of Entergy Corporation, responsible for unregulated power investments. Until July 2002, he served as Chief Operating Officer of Entergy Wholesale Operations, where his responsibilities included global development activities focusing on commercial development. Mr. Childers served as Senior Vice President & Chief Development Officer of Entergy Wholesale Operations from January 2000 until being named COO in September 2001. Before joining Entergy, Mr. Childers served as Vice President of Development of Edison Mission Energy from November 1997 to January 2000, where he was primarily responsible for implementing that company’s development, acquisition and marketing plan for North and South America. From August 1996 to November 1997, Mr. Childers was a director at Enron Corp., where he coordinated and supervised power and gas marketing, financial derivative and market development activities for Enron’s North American energy services unit. Previously, Mr. Childers was a senior manager of business development for Diamond Energy, Inc., and prior to that, he served as coordinator of business development for Texaco Cogeneration and Power. Mr. Childers received his BBA from the University of San Diego.

Joseph S. Compofelice. Mr. Compofelice is the Chief Executive Officer of Aquilex Services Corp., a provider of services and equipment to the power generation and heavy processing industries. For the period 1998 to 2001, Mr. Compofelice was Chairman and CEO of CompX International Inc., a producer of hardware for the office furniture industry. From 1994 through 1997, Mr. Compofelice was a Director and CFO of NL Industries Inc., a chemical producer, and Director and CFO of TIMET, a producer of titanium metal principally for the aerospace industry. Mr. Compofelice received his BS at California State University at Los Angeles and his MBA at Pepperdine University. Mr. Compofelice is a Director of Trico Marine Inc. and a member of the Board of Advisors of Courtland Inc., a privately held investment management firm.

Darrell W. Williams. Mr. Williams is an international business consultant working through the firm of Williams and Associates, Inc. From 1993 until 2002, Mr. Williams was associated with the German firm of Deutag Drilling, GmbH in both marketing and operations positions. In September 1996, he was transferred to Germany and served as Managing Director of Deutag International, which had responsibility for all drilling operations outside of Europe. Prior to joining Deutag, Mr. Williams was in senior executive positions with Nabors Drilling (1988-1993), Pool Company (1985-1988), Baker Oil Tools (1980-1983), SEDCO (1970-1980), Tenneco (1966-1970), and Humble Oil (1964-1966). Mr. Williams graduated from West Virginia University with a degree in Petroleum Engineering in 1964. Mr. Williams is past Chairman of the Houston Chapter of

International Association of Drilling Contractors, a member of the Society of Petroleum Engineers and a registered professional engineer in Texas. He also serves as a director of SMDC, Inc. (a wholly owned subsidiary of Hydril), which is engaged in the development of deep water drilling systems.

Directors of Contango serve as members of the board of directors until the next annual stockholders meeting, until successors are elected and qualified or until their earlier resignation or removal. Officers of Contango are elected by the board of directors and hold office until their successors are chosen and qualified, until their death or until they resign or have been removed from office. All corporate officers serve at the discretion of the board of directors. Directors are compensated in the form of both a cash payment and Company equity. Each outside director receives a quarterly cash retainer of $3,000 and a quarterly stock option grant to purchase 3,000 shares of common stock. Each outside director receives a $1,000 cash payment for each board meeting and separately scheduled Audit Committee meeting attended. The Chairman of the Audit Committee receives an additional quarterly stock option grant to purchase 1,500 shares of common stock. There are no family relationships between any of our directors or executive officers.

Corporate Offices

We lease our corporate offices at 3700 Buffalo Speedway, Suite 960, Houston, Texas 77098. Our lease covers 2,850 square feet of space for a monthly rental of $5,819 per month through October 2003. On November 1, 2003, our monthly rental will be $5,284 per month through October 2006.

Code of Ethics

In December 2002, we adopted a Code of Ethics for senior management. A copy of our Code of Ethics has been filed as an exhibit to this Form 10-KSB and is also available on our Website at www.mcfx.biz.

Risk Factors

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

We have no ability to control the prices that we receive for natural gas and oil. Natural gas and oil prices fluctuate widely, and low prices could have a material adverse effect on our revenues, profitability and growth. Our revenues, profitability and future growth will depend significantly on natural gas and crude oil prices. Prices received also will affect the amount of future cash flow available for capital expenditures and repayment of indebtedness and will affect our ability to raise additional capital. Lower prices may also affect the amount of natural gas and oil that we can economically produce. Factors that can cause price fluctuations include:

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The domestic and foreign supply of natural gas and oil

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Overall economic conditions

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The level of consumer product demand

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Weather conditions

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The price and availability of alternative fuels

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

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The price of foreign imports

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Domestic and foreign governmental regulations

Because we have a limited operating history in the natural gas and oil industry, our future operating results are difficult to forecast. We entered the natural gas and oil exploration and production business in July 1999, and as a result, we have limited historical financial and operating information available on which to base your evaluation of our future performance. Additionally, because we have fewer financial resources than many companies in our industry, we may be at a disadvantage in bidding for acreage, seismic data and exploratory prospects and producing natural gas and oil properties.

Our ability to successfully execute our business plan is dependent on our ability to obtain adequate financing. Our business plan, which includes participation in 3-D seismic shoots, the drilling of exploration prospects and producing property acquisitions, has required and will require substantial capital expenditures. We anticipate that we will require additional financing to fund our planned growth. Our ability to raise additional capital will depend on the results of our operations and the status of various capital and industry markets at the time we seek such capital. Accordingly, we cannot be certain that additional financing will be available to us on acceptable terms, if at all. In particular, our credit facility imposes limits on our ability to borrow under the facility based on adjustments to the value of our hydrocarbon reserves, and our credit facility and the terms of our outstanding preferred stock limit our ability to incur additional indebtedness. In the event additional capital resources are unavailable, we may be required to curtail our exploration and development activities or be forced to sell some of our assets in an untimely fashion or on less than favorable terms.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present values of our reserves. The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this report.

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

Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves shown in this report. In addition, we 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. Some of the producing wells included in our reserve report have produced for a relatively short period of time as of June 30, 2003. Because some of our reserve estimates are not based on a lengthy production history and are calculated using volumetric analysis, these estimates are less reliable than estimates based on a more lengthy production history.

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

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

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

We are highly dependent on the technical services provided by our alliance partner, JEX, and could be seriously harmed if our alliance agreement were terminated. Because we have only four employees, none of whom are geoscientists or engineers, we are dependent upon alliance partners for the success of our natural gas and oil exploration projects and expect to remain so for the foreseeable future. In particular, we have an agreement with JEX to source, screen, generate and present exploration and acquisition opportunities to us. This agreement is cancelable by JEX with 180-days notice or 30-days notice if we are in default under our alliance agreement. Highly qualified explorationists or engineers are difficult to attract and retain in this industry. As a result, the loss of the services of JEX could have a material adverse effect on us and could prevent us from pursuing our business plan. Additionally, JEX’s loss of certain explorationists or engineers could have a material adverse effect on our operations as well.

We rely on the accuracy of the estimates in the reservoir engineering reports provided to us by our outside engineers. We have no in house reservoir engineering capability, and therefore must

accept the accuracy of the periodic reservoir reports provided to use by our outside reservoir engineers. If those reports prove to be inaccurate, our financial reports could have material misstatements. Further, we use the reports of our independent reservoir engineers in our financial planning. If the reports of the outside reservoir engineers prove to be inaccurate, we may make misjudgments in our financial planning.

Exploration is a high risk activity, and our participation in drilling activities may not be successful. Our future success will largely depend on the success of our exploration drilling program. Participation in exploration drilling activities involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

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Unexpected drilling conditions

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

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Pressure or irregularities in formations

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Equipment failures or accidents

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Adverse weather conditions

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Compliance with governmental requirements and laws, present and future

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

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

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

The natural gas and oil business involves many operating risks that can cause substantial losses. The natural gas and oil business involves a variety of operating risks, including:

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Blowouts, fires and explosions

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Surface cratering

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Uncontrollable flows of underground natural gas, oil or formation water

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Natural disasters

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Pipe and cement failures

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Casing collapses

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Stuck drilling and service tools

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Abnormal pressure formations

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

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

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Injury or loss of life

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Severe damage to and destruction of property, natural resources or equipment

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Pollution and other environmental damage

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Clean-up responsibilities

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Regulatory investigation and penalties

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Suspension of our operations

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Repairs necessary to resume operations

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

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

Failure to obtain approvals and permits for the LNG receiving terminal in Freeport, Texas from governmental and regulatory agencies could have a detrimental effect on the project. We own a 10% interest Freeport LNG Development, LP, formed to build a proposed LNG receiving facility in Freeport, Texas. Freeport LNG Development has yet to obtain several governmental and regulatory approvals and permits required in order to complete and maintain the Freeport LNG project. It may take several years of work to obtain the approvals and permits necessary to proceed with the construction and operation of an LNG receiving terminal. Freeport LNG Development has no control over the outcome of the review and approval process. If Freeport LNG Development is unable to obtain the approvals and permits, we may not be able to recover our investment in the project.

If we are not able to fund or finance our 10% ownership in the LNG receiving facility in Freeport, Texas, we may lose our 10% investment in the project. The cost to construct a LNG receiving facility is estimated in the range of $400 million. It is unlikely that we would have the financial resources to fund our 10% ownership share of construction costs. If we are unable to finance our share of the project costs or if the project is unable to secure project financing, we could lose our investment in the project.

Hedging our production may result in losses. From time to time, we enter into hedging arrangements on a portion of our natural gas and oil production to reduce our exposure to declines in the prices of natural gas and oil. The value of these arrangements can be volatile and can materially affect our future reported financial results. Hedging arrangements also expose us to risk of significant financial loss in some circumstances including the following:

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There is a change in the expected differential between the underlying price in the hedging agreement and actual prices received

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Production is less than expected

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Payments owed under derivative hedging contracts typically come due prior to receipt of the hedged months production revenues

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The other party to the hedging contract defaults on its contract obligations

In addition, these hedging arrangements can limit the benefit we would receive from increases in the prices for natural gas and oil. Furthermore, if we choose not to engage in hedging arrangements in the future, we may be more adversely affected by changes in natural gas and oil prices than our competitors who engage in hedging arrangements.

Our ability to market our natural gas and oil may be impaired by capacity constraints on the gathering systems and pipelines that transport our natural gas and oil. Most of our natural gas, and a substantial portion of our oil, is transported through gathering systems and pipelines, which we do not own. Transportation capacity on gathering systems and pipelines is occasionally limited and at times unavailable due to repairs or improvements being made to these facilities or due to capacity being utilized by other natural gas or oil shippers that may have priority transportation agreements. If the gathering systems or our transportation capacity is materially restricted or is unavailable in the future, our ability to market our natural gas or oil could be impaired and cash flow from the affected properties could be reduced, which could have a material adverse effect on our financial condition and results of operations.

Most of our natural gas and oil production is concentrated in south Texas and is sold to a single purchaser. Most of our current production comes from wells drilled in south Texas. This production is being sold on a spot market basis to a single purchaser. Any disruption of our pipeline or marketing arrangements or financial difficulties with our purchaser, or alternative marketing sources, could have an adverse effect on our ability to market our natural gas and oil production. Additionally, if our purchaser suffered financial difficulties, we might not be able to collect receivables from the purchaser.

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

purchased in error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we may not be able to proceed with our exploration and development of the lease site or may incur costs to remedy a defect. It may also happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion.

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

We are subject to complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or feasibility of doing business. Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment. Failure to comply with such rules and regulations could result in substantial penalties and have an adverse effect on us. These laws and regulations may:

•

Require that we obtain permits before commencing drilling

•

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

•

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

•

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

Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain only limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Moreover, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability, or we may be required to cease production from properties in the event of environmental damages. These laws and regulations have been changed frequently in the past. In general, these changes have imposed more stringent requirements that increase operating costs or require capital expenditures in order to remain in compliance. It is also possible that unanticipated factual developments could cause us to make environmental expenditures that are significantly different from those we currently expect. Existing laws and regulations could be changed and any such changes could have an adverse effect on our business and results of operations.

We cannot control the activities on properties we do not operate. Other companies operate all of the properties in which we have an interest. As a result, we have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors that are outside of our control, including:

•

Timing and amount of capital expenditures

•

The operator’s expertise and financial resources

•

Approval of other participants in drilling wells

•

Selection of technology

Acquisition prospects are difficult to assess and may pose additional risks to our operations. We expect to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considers favorable. In particular, we expect to pursue acquisitions that have the potential to increase our domestic natural gas and oil reserves. The successful acquisition of natural gas and oil properties requires an assessment of:

•

Recoverable reserves

•

Exploration potential

•

Future natural gas and oil prices

•

Operating costs

•

Potential environmental and other liabilities and other factors

•

Permitting and other environmental authorizations required for our operations

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

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

•

Problems integrating the purchased operations, personnel or technologies

•

Unanticipated costs

•

Diversion of resources and management attention from our exploration business

•

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

•

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

We do not currently intend to pay dividends on our common stock. We have never declared or paid a dividend on our common stock and do not expect to do so in the foreseeable future. Our current plan is to retain any future earnings for funding growth, and, therefore, holders of our common stock will not be able to receive a return on their investment unless they sell their shares.

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

•

Designate the terms of and issue new series of preferred stock

•

Limit the personal liability of directors

•

Limit the persons who may call special meetings of stockholders

•

Prohibit stockholder action by written consent

•

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

•

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

•

Impose restrictions on business combinations with some interested parties

Item 2.

Description of Properties

Production, Prices, Operating Expenses, EBITDAX and Other

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

	Year Ended June 30,
	2003		2002
Production:
Natural gas (thousand cubic feet)		6,016,395		6,981,909
Oil and condensate (barrels)		138,569		186,274
Total (thousand cubic feet equivalent)		6,847,809		8,099,553
Natural gas (thousand cubic feet per day)		16,483		19,129
Oil and condensate (barrels per day)		380		510
Total (thousand cubic feet equivalent per day)		18,763		22,189
Average sales price:
Natural gas (per thousand cubic feet)	$	5.00	$	2.94
Oil and condensate (per barrels)	$	27.90	$	21.44
Total (per thousand cubic feet equivalent)	$	4.95	$	3.03
Selected data per Mcfe:
Production and severance taxes	$	0.35	$	0.20
Lease operating expense	$	0.48	$	0.28
General and administrative expense	$	0.30	$	0.36
Depreciation, depletion and amortization of natural gas and oil properties	$	1.24	$	1.05
EBITDAX (1)	$	20,900,941	$	22,485,600

(1)

EBITDAX represents earnings before interest, income taxes, depreciation, depletion and amortization, impairment expenses, 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.

	Year Ended June 30,
	2003			2002
Income (loss) from operations	$	(6,481,309	)	$	10,296,851
Exploration expenses		17,922,116			2,694,425
Depreciation, depletion and amortization		8,787,794			8,593,635
Impairment of natural gas and oil properties		181,610			527,150
Gain on sale of assets and other		490,730			373,539

EBITDAX	$	20,900,941		$	22,485,600

Development, Exploration and Acquisition Capital Expenditures

The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties and in exploration and development activities for the periods indicated:

	Year Ended June 30,
	2003		2002
Property Acquisition Costs:
Unproved	$	972,658	$	1,063,204
Proved		2,602,551		23,449,488
Exploration costs		19,194,281		7,138,690

Total costs	$	22,769,490	$	31,651,382

Drilling Activity

The following table shows our drilling activity for the periods indicated. In the table, “gross” wells refer to wells in which we have a working interest, and “net” wells refer to gross wells multiplied by our working interest in such wells.

	Year Ended June 30,
	2003		2002
	Gross	Net	Gross	Net
Exploratory Wells:
Productive	11	5.2	9	6.5
Non-productive	4	1.9	3	1.4

Total	15	7.1	12	7.9

We drilled no development wells during the periods indicated.

Exploration and Development Acreage

Our principal natural gas and oil properties consist of natural gas and oil leases. The following table indicates our interests in developed and undeveloped acreage as of June 30, 2003:

	Developed Acreage (1)(2)		Undeveloped Acreage (1)(3)
	Gross (4)	Net (5)	Gross (4)	Net (5)
Onshore:
Texas	10,793	7,106	1,242	89
Offshore Outer Continental Shelf:
Louisiana and Texas	1,250	267	30,985	27,111

Total	12,043	7,373	32,227	27,200

(1)

Excludes any interest in acreage in which we have no working interest before payout.

(2)

Developed acreage consists of acres spaced or assignable to productive wells.

(3)

Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.

(4)

Gross acres refer to the number of acres in which we own a working interest.

(5)

Net acres represents the number of acres attributable to an owner’s proportionate working interest and/or royalty interest in a lease (e.g., a 50% working interest in a lease covering 320 acres is equivalent to 160 net acres).

The above table includes our 33.3% % interest in 19,651 gross offshore undeveloped acres (17,964 net undeveloped acres) held by Republic Exploration, excludes our 50% interest in 10,760 gross offshore undeveloped acres (10,760 net undeveloped acres) held by Magnolia Offshore Exploration and excludes our 66.7% interest in 21,082 gross offshore undeveloped acres (21,082 net undeveloped acres) held by Contango Offshore Exploration.

Productive Wells

The following table sets forth the number of gross and net productive natural gas and oil wells in which we owned an interest as of June 30, 2003:

	Total Productive Wells (1)
	Gross (2)	Net (3)
Natural gas	46	28.0
Oil	1	0.5

Total	47	28.5

(1)

Productive wells are producing wells and wells capable of production.

(2)

A gross well is a well in which we own an interest.

(3)

The number of net wells is the sum of our fractional working interests owned in gross wells.

Natural Gas and Oil Reserves

The following table presents our estimated net proved natural gas and oil reserves and the pre-tax net present value of our reserves at June 30, 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 reserves prepared in accordance with SEC guidelines as of June 30, 2003 was determined by the June 30, 2003 prices of $5.235 per MMbtu for natural gas and $30.19 per barrel of oil, in each case before adjusting for basis, transportation costs and Btu content. For further information concerning the present value of future net cash flows from these proved reserves, see “Supplemental Oil and Gas Disclosures”.

	Total Proved Reserves as of June 30, 2003
	Producing		Behind Pipe		Undeveloped		Total
Natural gas (MMcf)		20,833		206		183		21,222
Oil and condensate (Bbls)		348		47		—		395
Total proved reserves (MMcfe)		22,921		488		183		23,592
Pre-tax net present value	$	67,834,107	$	1,038,241	$	754,802	$	69,627,150

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. We must project production rates and timing of development expenditures. We analyze available geological, geophysical, production and engineering data, and 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, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control. Because most of our reserve estimates are not based on a lengthy production history and are calculated using volumetric analysis, these estimates are less reliable than estimates based on a lengthy production history.

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

Item 3.

Legal Proceedings

As of the date of this Form 10-KSB, we are not a party to any legal proceedings, and we are not aware of any proceeding contemplated against us.

Item 4.

Submission of Matters to a Vote of Security Holders

During the quarter ended June 30, 2003, no matters were submitted to a vote of security holders.

PART II

Item 5.

Market for Common Equity and Related Stockholder Matters

Our common stock was listed on the American Stock Exchange in January 2001 under the symbol “MCF”. The table below shows the high and low closing prices of our common stock for the periods indicated.

	High		Low
Fiscal Year 2002:
Quarter ended September 30, 2001	$	4.00	$	2.30
Quarter ended December 31, 2001	$	3.04	$	2.35
Quarter ended March 31, 2002	$	3.46	$	2.55
Quarter ended June 30, 2002	$	3.94	$	2.40
Fiscal Year 2003:
Quarter ended September 30, 2002	$	3.39	$	2.59
Quarter ended December 31, 2002	$	3.39	$	2.56
Quarter ended March 31, 2003	$	3.44	$	2.80
Quarter ended June 30, 2003	$	4.10	$	2.86

On September 12, 2003, the closing price of our common stock on the American Stock Exchange was $4.25 per share, and there were 9,301,692 shares of Contango common stock outstanding, held by 140 holders of record.

We have not declared or paid any dividends on our shares of common stock and do not currently anticipate paying any dividends on our shares of common stock in the future. Currently, except for the regular dividends that we pay on our Series A and Series B preferred stock, our plan is to retain any future earnings for use in the operations and expansion of our natural gas and oil business. Our credit facility currently prohibits us from paying any cash dividends on our common stock. The credit facility does, however, permit the payment of stock dividends on our common stock. Any future decision to pay dividends on our common stock will be at the discretion of our board and will depend upon our financial condition, results of operations, capital requirements, and other factors our board may deem relevant.

On March 28, 2002, Contango repurchased 2,575,000 shares of Contango common stock owned by the SUIT Growth Fund for $6,180,000. This share repurchase represents a 22% reduction in Contango’s outstanding common shares. The SUIT Growth Fund originally purchased these securities in private placements during June and August 2000. In addition, the Company cancelled a warrant held by the SUIT Growth Fund to purchase 125,000 shares of its common stock at $2.00 per share and options to purchase 17,500 shares of its common stock at prices between $2.70 and $5.87 per share. In connection with these transactions, Robert J. Zahradnik, Director of Operations of the SUIT Growth Fund and a Contango director, tendered his resignation as a director to the Company.

During the fiscal year ended June 30, 2002, we issued 3,900 shares of common stock to two employees and an outside consultant at values ranging from $2.45 per share to $3.46 per share as consideration for their services. The issuance of these securities was exempt from registration under Section 4(2) of the Securities Act, as it did not involve a public offering of securities.

During the fiscal year ended June 30, 2003, no shares of common stock were issued to employees or consultants.

Item 6.

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 related notes and other information included elsewhere in this report.

Introduction

The following is a discussion of the results of our operations for the fiscal year ended June 30, 2003, compared to the fiscal year ended June 30, 2002.

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 and stock options.

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

When circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a well-by-well basis to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future natural gas and oil prices and operating costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced

to fair market value. During the fiscal year ended June 30, 2003 and 2002, the Company recorded impairments of $181,610 and $527,150, respectively, related to natural gas and oil properties.

Principles of Consolidation. The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries and affiliates, after elimination of all intercompany balances and transactions. Wholly owned subsidiaries are fully consolidated. Subsidiaries not wholly owned, such as 33.3% owned Republic Exploration LLC (“Republic Exploration”), 50.0% owned Magnolia Offshore Exploration LLC (“Magnolia Offshore Exploration”) and 66.7% owned Contango Offshore Exploration LLC (“Contango Offshore Exploration”) are not controlled by the Company and are proportionately consolidated. By agreement, Republic Exploration, Magnolia Offshore Exploration and Contango Offshore Exploration have disproportionate allocations of their profits and losses among the owners. Accordingly, the Company determines its income or losses from the ventures based on a hypothetical liquidation determination of how increases or decreases in the book value of the ventures’ net assets will ultimately affect the cash payments to the Company in the event of dissolution.

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 June 30, 2003, as opposed to 100% of each ventures’ net assets as of June 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 $249,000, respectively, for the year ended June 30, 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.

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

In June 1998, the FASB issued SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”. SFAS No. 133 established accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts), as defined, be recorded in the balance sheet as either an asset or liability measured at fair value and requires that changes in fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

Although the Company’s hedging transactions generally are designed as economic hedges for a portion of future natural gas and oil production, the Company has elected not to designate the derivative instruments as “hedges” under SFAS No. 133. As a result, gains and losses, representing changes in these derivative instruments’ mark-to-market fair values, are recognized currently in the Company’s earnings (see footnote 9 for more information on hedging activities).

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

Effective July 1, 2001, the Company prospectively changed its method of accounting for employee stock-based compensation to the fair value based method prescribed in Statement of Financial Accounting Standards No. 123, “Accounting for Stock Based Compensation”. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the award vesting period. The fair value of each award is estimated as of the date of grant using the Black-Scholes options-pricing model.

The Company has determined that the fair value method is preferable to the intrinsic value method previously applied. During the fiscal year ended June 30, 2003 and 2002, the Company recorded a charge of $134,431 and $29,796 to general and administrative expense related to fiscal year 2003 and 2002 grants, respectively. Because compensation expense is recognized over a vesting period, the effect of applying the fair value method in the initial years of implementation may not be representative of the effects on net income (loss) that will be reported in future years.

MD&A Summary Data

The table below sets forth, for the periods indicated, summary information discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations below.

	Year Ended June 30,
	2003			2002			Change
Natural gas and oil sales	$	33,919,126		$	23,901,995		42	%
Gain (loss) from hedging activities	$	(5,708,958	)	$	5,016,173		n/a
Production:
Natural gas (thousand cubic feet per day)		16,483			19,129		-14	%
Oil and condensate (barrels per day)		380			510		-25	%
Average sales price:
Natural gas (per thousand cubic feet)	$	5.00		$	2.94		70	%
Oil and condensate (per barrels)	$	27.90		$	21.44		30	%
Operating expenses	$	5,736,454		$	3,904,541		47	%
Exploration expenses	$	17,922,116		$	2,694,425		565	%
Depreciation, depletion and amortization	$	8,787,794		$	8,593,635		2	%
Impairment of natural gas and oil properties	$	181,610		$	527,150		-66	%
General and administrative expense	$	2,063,503		$	2,901,566		-29	%
Interest expense	$	710,587		$	285,159		149	%
Gain on sale of assets and other	$	490,730		$	373,539		31	%
Income tax (expense) benefit	$	2,334,782		$	(4,003,154	)	n/a

Year ended June 30, 2003 Compared to Year ended June 30, 2002

Natural Gas and Oil Sales. We reported natural gas and oil sales of approximately $33.9 million for the year ended June 30, 2003, up from approximately $23.9 million reported for the year ended June 30, 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 year ended June 30, 2003, our net natural gas production decreased from approximately 19.1 million cubic feet of natural gas per day to approximately 16.5 million cubic feet of natural gas per day. Net oil production for the period was down from 510 barrels of oil per day to 380 barrels of oil per day. These decreases primarily were due to the natural decline in production from our original STEP properties, which was partially offset by new production from south Texas discoveries made during year ended June 30, 2003. For the year ended June 30, 2003, prices for natural gas and oil were $5.00 per Mcf and $27.90 per barrel, up substantially from $2.94 per Mcf and $21.44 per barrel for the year ended June 30, 2002.

Gain (loss) from Hedging Activities. We reported a loss from hedging activities for the year ended June 30, 2003 of approximately $5.7 million. This loss included an approximate $5.8 million realized loss on various swap, put and call agreements that was offset by an unrealized gain of about $67,000. For the year ended June 30, 2002, we recognized a gain from hedging activities of approximately $5.0 million. This gain consisted primarily of gains on settlements of swap derivative agreements (see footnote 9 to Notes to Consolidated Financial Statements).

Operating Expenses. Operating expenses, including severance taxes, for the year ended June 30, 2003 were approximately $5.7 million, up from the $3.9 million reported for the year ended June 30, 2002. Of the $5.7 million reported for the year ended June 30, 2003, approximately $3.3 million was attributable to lease operating expense and approximately $2.4 million was attributable to production and severance taxes. Operating expenses for the year ended June 30, 2002 included approximately $2.2 million of lease operating expenses and approximately $1.7 million of production and severance taxes. The increase in operating expenses for the year ended June 30, 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 $17.9 million of exploration expenses for the year ended June 30, 2003. Of this amount, approximately $11.9 million was attributable to the cost to acquire and reprocess 3-D seismic data offshore in the Gulf of Mexico, approximately $4.7 million was the cost to shoot and to acquire 3-D seismic in south Texas and approximately $1.3 million was related to dry hole costs in south Texas. For the year ended June 30, 2002, we reported approximately $2.7 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 $500,000 of seismic costs and delay rentals attributable to activities offshore in the Gulf of Mexico.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the year ended June 30, 2003 was approximately $8.7 million. This was attributable primarily to depletion and amortization related to production onshore in south Texas. For the year ended June 30, 2002, we recorded approximately $8.6 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 primarily to the increase in amortization of fees related to our bank credit facility.

Impairment of Natural Gas and Oil Properties. Impairment expense for the year ended June 30, 2003 was approximately $181,600. This related to impairment of properties held by Republic Exploration and Magnolia Offshore Exploration. Impairment expense for the year ended June 30, 2002 was approximately $527,200 and related to impairment of a lease prospect in south Texas and to an impairment of one of our offshore wells.

General and Administrative Expenses. General and administrative expenses decreased from approximately $2.9 million for the year ended June 30, 2002 to approximately $2.1 million for the year ended June 30, 2003. Major components of general and administrative expenses for the year ended June 30, 2003 included approximately $497,400 in salaries and benefits, $722,600 in legal, accounting, engineering and other professional fees (including $235,200 of one time costs associated with the proposed sale of our STEP properties and property ownership restructuring), $267,400 of office administration and $130,400 of insurance costs. Also included in total general and administrative expenses for the year ended June 30, 2003 was approximately $134,400 related to the cost of expensing stock options, $167,100 attributable to activities of Republic Exploration, Magnolia Offshore Exploration and Contango Offshore Exploration, $66,000 for Board compensation expense and $78,200 in other expenses.

Major components of general and administrative expenses for the year ended June 30, 2002 included approximately $963,300 in salaries and benefits, $1,047,100 in legal, accounting, engineering and other professional fees (including $542,800 of one time costs associated with the proposed public offering of our Series C preferred stock), $207,100 of office administration and $125,700 of insurance costs. Also included in total general and administrative expenses for the year ended June 30, 2002 was approximately $29,800 related to the cost of expensing stock options, $301,900 attributable to activities of Republic Exploration and Magnolia Offshore Exploration and $226,600 in other expenses.

The decrease in general and administrative expenses was primarily due to decreases in salaries and benefits (resulting primarily from a lower level of bonus payments), decreases in legal expenses (as noted above) and lower non-cash costs of Republic Exploration.

Interest Expense. We reported interest expense of approximately $710,600 for the year ended June 30, 2003, up from the $285,200 reported for the year ended June 30, 2002. This increase was attributable to a higher average level of borrowings under our credit facility primarily to fund seismic and other geological and geophysical costs and to acquire properties in south Texas. We had no bank borrowings prior to January 1, 2002.

Gain on Sale of Assets and Other. We reported a gain of $490,700 for the year ended June 30, 2003. This primarily was attributable to a $451,500 unrealized mark-to-market gain at June 30, 2003 on Cheniere Energy common stock acquired through the partial exercise of a Cheniere Energy warrant (see footnote 14 to Notes to Consolidated Financial Statements). For the year ended June 30, 2002, we reported a gain of approximately $373,500. This was attributable to gains on leases sold by Republic Exploration and to gains realized on the sale of certain partnership interests and properties located in Colorado and Ft. Bend Counties, Texas.

Capital Resources and Liquidity

During the year ended June 30, 2003, we funded our activities with cash on hand, internally generated cash flow and borrowings under our secured, reducing revolving line of credit with Guaranty Bank, FSB that matures in June 2006. We reported total revenues for the year ended June 30, 2003 of approximately $28.2 million, which included approximately $5.7 million of net loss from hedging activities. EBITDAX, which we define as earnings before interest, income taxes, depreciation, depletion and amortization, impairment expense and expensed exploration expenditures, including gains or losses from hedging, for the year ended June 30, 2003 was approximately $20.9 million.

In September 2003 we completed the sale of certain non-core reserves in Brooks County, Texas for $5.0 million. Proved reserves were 1.5 Bcfe and accounted for approximately $5.0 million of the Company’s discounted present value at 10% per annum as of June 30, 2003. The effective sales date was July 1, 2003. Our current production rate following the sale of these properties is approximately 16,000 MMbtue per day. At anticipated production levels and current commodity price levels, we expect to have cash flow of $1.5 to $2.0 million per month through December 2003.

We are continuing our exploration efforts in the south Texas. On our original STEP properties, drilling has started on a Queen City development well. We recently completed our

second 3-D seismic shoot in Jim Hogg and Starr Counties, Texas, covering approximately 100 square miles at a cost of approximately $2.2 million. The processing and evaluation of this data is now complete, and we expect to drill an initial Queen City well in October 2003. If this play develops, we would expect to drill another five to seven wells with expenditures in the $3.0 to $4.0 million range.

Offshore, two wells have been successfully drilled on Eugene Island 110, a lease block farmed out by Contango and Republic Exploration. Production commenced during the summer of 2003 and is currently averaging approximately 20.0 MMcf of natural gas and 1,500 barrels of oil per day. Based on current production rates and prices, we expect Contango and Republic Exploration will earn their after payout working interests during the first half of 2004, and we expect to receive approximately $400,000 per month cash flow after payout. Contango, Republic Exploration and Magnolia Offshore Exploration have recently farmed out three “deep shelf” lease blocks. Magnolia Offshore Exploration’s lease block, Viosca Knoll 211, is currently drilling. The two lease blocks farmed out by Contango and Republic Exploration, Eugene Island 113B and Vermillion 73 are expected to spud by year-end 2003.

In August 2003, Contango Offshore Exploration and Republic Exploration participated in the Gulf of Mexico Lease Sale #187. Republic Exploration was high bidder on one lease block, and Contango Offshore Exploration was apparent high bidder on four lease blocks. Since Contango funds all of Contango Offshore Exploration’s lease costs, Contango’s obligation, if the leases are awarded, is approximately $1.3 million. An apparent high bid gives the bidding party priority in award of offered tracts, notwithstanding the fact that the Minerals Management Service may reject all bids for a given tract. The review process can take up to 90 days on some bids. Three of Contango Offshore Exploration’s lease blocks are located in the East Breaks area and are in deep water (1,600 to 2,500 feet). If awarded, they represent a new exploration region for Contango. As with our deep shelf exploration, our business plan is to farmout these prospects and retain only a reversionary working interest or an overriding royalty interest. Contango expects that Republic Exploration and Contango Offshore Exploration will participate in the Central Gulf of Mexico lease sale to be held in March 2004. Contango and its partially owned subsidiaries are fully carried on all drilling and completion costs on these prospects.

Commission (“FERC”) approval for the project. A response from the FERC is not expected prior to the first quarter of 2004.

In June 2003, Contango exercised a warrant to purchase 150,000 shares of Cheniere common stock. In August 2003, Contango sold the 150,000 shares of Cheniere common for a net gain of $577,400. At June 30, 2003, the 150,000 shares of Cheniere common stock had a mark-to-market valuation of $451,500. In September 2003, Contango exercised a warrant to purchase the remaining 150,000 shares of Cheniere common stock for a price of $375,000.

We believe that our cash on hand, our anticipated cash flow from operations and funds available under our credit facility will be adequate to satisfy planned capital expenditures over the next 12 months. We may seek additional equity, sell assets or seek other financing to fund possible acquisitions and an expanded exploration program, and to take advantage of other opportunities that may become available. The availability of such funds will depend upon prevailing market conditions and other factors over which we have no control, as well as our financial condition and results of operations.

Credit Facility

Our credit facility is a secured, reducing revolving line of credit with Guaranty Bank, FSB, secured by our natural gas and oil reserves. On September 19, 2003, our borrowing base was redetermined to $24.2 million in two tranches. Tranche A provides for a borrowing base of $21.7 million and matures on June 29, 2006. This amount reduces by $620,000 per month the first day of each month beginning October 1, 2003. Borrowings under Tranche A bear interest, at our option, at either (i) LIBOR plus two percent (2%) or (ii) the bank’s base rate plus one-fourth percent (1/4%) per annum. Additionally, we pay a quarterly commitment fee of three-eighths percent (3/8%) per annum on the average availability of Tranche A. Tranche B provides for a borrowing base of $2.5 million and matures on March 1, 2004. This amount reduces by $425,000 per month the first day of each month beginning October 1, 2003. Borrowings under Tranche B bear interest, at our option, at either (i) LIBOR plus three percent (3%) or (ii) the bank’s base rate plus three-quarters percent (3/4%) per annum. Additionally, we pay a quarterly commitment fee of one-half percent (1/2%) per annum on the average availability under Tranche B.

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

As of June 30, 2003, $22.35 million was outstanding under the credit facility, and we were in compliance with all financial covenants and ratios. At September 12, 2003, we had approximately $232,100 in cash on hand, $12.3 million borrowed under our credit facility and $11.4 million of unused bank borrowing capacity.

Quantitative and Qualitative Disclosure About Market Risk

Commodity Risk. Our major commodity price risk exposure is to the prices received for our natural gas and oil production. Realized commodity prices received for our production are the spot prices applicable to natural gas and crude oil. Prices received for natural gas and oil are volatile and unpredictable and are beyond our control. For the year ended June 30, 2003, a 10% fluctuation in the prices received for natural gas and oil production would have had an approximate $3.4 million impact on our revenues.

In the past, we periodically entered into hedges on a portion of our projected natural gas and oil production to manage our exposure to declines in natural gas and oil prices. We use these derivative financial instruments for non-trading purposes only. For the year ended June 30, 2003, we recognized a loss of approximately $5.7 million.

Hedging Activities. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil. These prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. 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. Lower prices may also reduce the amount of natural gas and oil that we can economically produce.

The following table provides our pricing and notional volumes on open commodity derivative contracts as June 30, 2003.

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

(1)

Prices and quantities per MMbtu.

At June 30, 2003, the mark-to-market valuation was a loss of $58,171. 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 and oil 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.

Interest Rate Risk. The carrying value of our debt approximates fair value. At June 30, 2003, we had $22.35 million of total long-term debt, $5.9 million of which was current. This matures in June 2006 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 June 30, 2003 was 3.14%. The results of a 10% fluctuation in short-term rates would have had an approximate $71,100 impact on interest expense for the year ended June 30, 2003.

Item 7.

Financial Statements and Supplementary Data

The financial statements and supplemental information required to be filed under this item are presented on pages Page F-1 through F-24 of this Form 10-KSB.

Item 8.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Previously reported on Form 8-K, dated June 14, 2002.

During our fiscal years ended June 30, 2003 and 2002, there were no disagreements between us and Grant Thornton LLP on any matter of accounting principles or practices, financial statement disclosure, or audit scope or procedures, which disagreements, if not resolved to Grant Thornton LLP’s satisfaction, would have caused Grant Thornton LLP to make reference to the subject matter of the disagreement in connection with its reports.

Item 8a.

Controls and Procedures

Within 90 days prior to the filing of this report, an evaluation was performed under the supervision and with the participation of the Company’s management, including the Chairman, President, Chief Executive Officer, and Chief Financial Officer and the Controller, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based on that evaluation, the Company’s management, including the Chairman, President, Chief Executive Officer and Chief Financial Officer and Controller, concluded that the Company’s disclosure controls and procedures were effective in ensuring that material information relating to the Company with respect to the periods covered by this report were made known to them. There have been no significant changes in the Company’s internal controls or in other factors that could significantly affect internal controls subsequent to the date of that evaluation.

PART III

Item 9.

Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act

The information regarding directors, executive officers, promoters and control persons required under Item 9 of Form 10-KSB will be contained in our Definitive Proxy Statement for our 2003 Annual Meeting of Stockholders (the “Proxy Statement”) under the headings “Election of Directors”, “Executive Compensation” and “Section 16(a) Beneficial Ownership Reporting Compliance” and is incorporated herein by reference. The Proxy Statement will be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Exchange Act of 1934, as amended, not later than 120 days after June 30, 2003.

Item 10.

Executive Compensation

The information required under Item 10 of Form 10-KSB will be contained in the Proxy Statement under the heading “Executive Compensation” and is incorporated herein by reference.

Item 11.

Security Ownership of Certain Beneficial Owners and Management and related Stockholder Matters.

(a) The required information contained in the Proxy Statement under the heading “Security Ownership of Certain Other Beneficial Owners and Management” is incorporated herein by reference.

(b) The following table provides information as of September 12, 2003 about our common stock that may be issued upon the exercise of stock options and warrants under (i) all compensation plans previously approved by security holders and (ii) all compensation plans not previously approved by security holders.

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities available for future issuance under equity compensation plans (excluding securities reflected in column (a))

Equity compensation plans approved by the security holders	1,702,166	$	2.60	1,597,749
Equity compensation plans not approved by the security holders	1,210,019	$	2.44	—

Total	2,912,185	$	2.54	1,597,749

See footnotes 12 and 13 to Consolidated Financial Statements for a narrative of the material features of our Option Plan that has been approved by security holders, as well as information about stock options and warrants issued that have not been approved by security holders.

Item 12.

Certain Relationships and Related Transactions

The information required under Item 12 of Form 10-KSB will be contained in the Proxy Statement under the heading “Certain Relationships and Related Transactions” and “Executive Compensation” and is incorporated herein by reference.

Item 13.

Exhibits and Reports on Form 8-K

(a) Exhibits:

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

10.23		Fifth Amendment, effective June 1, 2003, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (19)

14.1		Code of Ethics. †

21.1		Subsidiaries of the Company. †

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

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

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

†

Filed herewith.

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.

19.

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

(b) Reports on Form 8-K:

On June 18, 2003, we filed a news release dated June 17, 2003 on Form 8-K reporting that the borrowing base on our existing secured revolving line of credit with Guaranty Bank, FSB had been increased from $23.5 million to $27.0 million and that the final maturity had been extended two years to June 29, 2006.

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

CONTANGO OIL & GAS COMPANY

/s/ KENNETH R. PEAK				/s/ LESIA BAUTINA

Kenneth R. Peak				Lesia Bautina
Chairman, Chief Executive Officer and Chief				Vice President and Controller
Financial Officer (principal executive officer				(principal accounting officer)
and principal financial officer)

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name	Title	Date

/s/ KENNETH R. PEAK Kenneth R. Peak	Chairman of the Board	September 22, 2003

/s/ JAY BREHMER Jay Brehmer	Director	September 22, 2003

/s/ MICHAEL P. CHILDERS Michael P. Childers	Director	September 22, 2003

/s/ JOSEPH S. COMPOFELICE Joseph S. Compofelice	Director	September 22, 2003

/s/ DARRELL W. WILLIAMS Darrell W. Williams	Director	September 22, 2003

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

		Page
Reports of Independent Certified Public Accountants		F-2

Consolidated Balance Sheets, June 30, 2003 and 2002		F-3

Consolidated Statements of Operations for the Years Ended June 30, 2003 and 2002		F-5

Consolidated Statements of Cash Flows for the Years Ended June 30, 2003 and 2002		F-6

Consolidated Statements of Shareholders’ Equity for the Years Ended June 30, 2003 and 2002		F-7

Notes to Consolidated Financial Statements		F-8

Supplemental Oil and Gas Disclosures		F-22

F-1

REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

To the Shareholders of Contango Oil & Gas Company:

We have audited the accompanying consolidated balance sheets of Contango Oil & Gas Company (a Delaware corporation) and subsidiaries as of June 30, 2003 and 2002, and the related consolidated statements of operations, shareholders’ equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Contango Oil & Gas Company and subsidiaries as of June 30, 2003 and 2002, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

GRANT THORNTON LLP

Houston, Texas

September 15, 2003

F-2

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

	June 30,
	2003			2002
CURRENT ASSETS:
Cash and cash equivalents	$	219,242		$	2,726,845
Accounts receivable, net		6,039,779			5,220,453
Advances to operators		—			597,294
Price hedge contracts		—			57,726
Marketable equity securities		676,500			—
Other		96,115			184,437

Total current assets		7,031,636			8,786,755

PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties		55,125,109			46,565,998
Unproved properties, not being amortized		3,065,188			3,650,558
Furniture and equipment		126,388			188,884
Accumulated depreciation, depletion and amortization		(21,574,673	)		(13,056,575	)

Total property, plant and equipment		36,742,012			37,348,865

OTHER ASSETS:
Cash and other assets held by affiliates		784,656			4,732,726
Investment in LNG project		850,000			750,000
Investment in NOSR project		75,000			75,000
Deferred income tax asset		568,024			—
Facility fee		177,500			135,826
Other assets		76,112			10,344

Total other assets		2,531,292			5,703,896

TOTAL ASSETS	$	46,304,940		$	51,839,516

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

F-3

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

	June 30,
	2003			2002
CURRENT LIABILITIES:
Accounts payable	$	681,425		$	613,537
Accrued exploration and development		1,011,098			517,000
Income taxes payable		734,312			1,040,788
Price hedge contracts		58,171			183,400
Short term hedge payable		102,486			525,870
Other accrued liabilities		229,937			648,654
Current portion of long-term debt		5,890,000			1,330,000

Total current liabilities		8,707,429			4,859,249

LONG-TERM DEBT		16,460,000			17,620,000
ASSET RETIREMENT OBLIGATION		191,664			—
DEFERRED CREDITS		208,333			483,920
DEFERRED INCOME TAX LIABILITY		—			3,777,864
SHAREHOLDERS’ EQUITY:
Convertible preferred stock, 8%, Series A, $0.04 par value, 5,000 shares authorized, 2,500 shares issued and outstanding at June 30, 2003 and 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 June 30, 2003 and 2002, liquidation preference of $1,000 per share		200			200
Common stock, $0.04 par value, 50,000,000 shares authorized, 11,871,076 issued and 9,296,076 outstanding at June 30, 2003, 11,618,282 issued and 9,043,282 shares issued and outstanding at June 30, 2002		473,399			464,732
Additional paid-in capital		21,803,090			21,236,701
Treasury stock at cost (2,575,000 shares)		(6,180,000	)		(6,180,000	)
Retained earnings		4,640,725			9,576,750

Total shareholders’ equity		20,737,514			25,098,483

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	46,304,940		$	51,839,516

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

F-4

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended June 30,
	2003			2002
REVENUES:
Natural gas and oil sales	$	33,919,126		$	23,901,995
Gain (loss) from hedging activities		(5,708,958	)		5,016,173

Total revenues		28,210,168			28,918,168

EXPENSES:
Operating expenses		5,736,454			3,904,541
Exploration expenses		17,922,116			2,694,425
Depreciation, depletion and amortization		8,787,794			8,593,635
Impairment of natural gas and oil properties		181,610			527,150
General and administrative expense		2,063,503			2,901,566

Total expenses		34,691,477			18,621,317

INCOME (LOSS) FROM OPERATIONS		(6,481,309	)		10,296,851
Interest expense		(710,587	)		(285,159	)
Interest income		30,359			194,905
Gain on sale of assets and other		490,730			373,539

INCOME (LOSS) BEFORE INCOME TAXES		(6,670,807	)		10,580,136
(Provision) benefit for income taxes		2,334,782			(4,003,154	)

NET INCOME (LOSS)		(4,336,025	)		6,576,982
Preferred stock dividends		600,000			600,000

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(4,936,025	)	$	5,976,982

NET INCOME (LOSS) PER SHARE:
Basic	$	(0.54	)	$	0.55

Diluted	$	(0.54	)	$	0.48

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		9,129,169			10,841,665

Diluted		9,129,169			13,711,597

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

F-5

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended June 30,
	2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(4,336,025	)	$	6,576,982
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		8,787,794			8,593,635
Impairment expense		181,610			527,150
Exploration expenditures		6,351,117			2,236,515
Provision (benefit) for deferred income taxes		(4,345,888	)		598,616
Gain on sale of assets and other		(490,730	)		(373,539	)
Unrealized (gain) loss on hedges		(64,423	)		1,014,074
Stock-based compensation		141,723			56,808
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(819,326	)		74,186
Increase in marketable equity securities		(225,000	)		—
Decrease in prepaid insurance		118,713			1,901
Increase (decrease) in accounts payable		(594,933	)		1,496,307
Increase (decrease) in other accrued liabilities		(211,585	)		311,768
Increase (decrease) in taxes payable		(306,476	)		1,040,788
Other		(92,053	)		317,368

Net cash provided by operating activities		4,094,518			22,472,559

CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration expenditures		(8,595,940	)		(7,743,984	)
Decrease (increase) in cash and other assets held by affiliates		850,000			(1,612,860	)
Investment in LNG project		(100,000	)		(750,000	)
Addition to furniture and equipment		(16,560	)		(15,854	)
Decrease (increase) in advances to operators		853,347			(311,068	)
Purchase of proved producing reserves		(2,599,485	)		(23,298,931	)
Acquisition costs		(3,066	)		(150,557	)
Proceeds from sale of assets and other		—			261,448

Net cash used in investing activities		(9,611,704	)		(33,621,806	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		29,670,000			31,050,000
Repayments under credit facility		(26,270,000	)		(12,100,000	)
Purchase of treasury shares		—			(6,180,000	)
Preferred stock dividends		(600,000	)		(600,000	)
Proceeds from exercised options and warrants		433,333			225,000
Debt issue costs		(223,750	)		(105,250	)

Net cash provided by financing activities		3,009,583			12,289,750

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(2,507,603	)		1,140,503
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		2,726,845			1,586,342

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	219,242		$	2,726,845

SUPPLMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for taxes	$	2,549,788		$	2,355,000

Cash paid for interest	$	711,808		$	265,664

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

F-6

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

																Total Shareholders’ Equity
	Preferred Stock			Common Stock				Paid-in Capital		Treasury Stock			Retained Earnings
	Shares	Amount		Shares		Amount		Paid-in Capital		Treasury Stock			Retained Earnings
Balance at June 30, 2001	7,500		300	11,501,882			460,076		20,959,549		—			3,599,768			25,019,693
Stock-based compensation	—		—	3,900			156		11,106		—			—			11,262
Exercise of stock options and warrants	—		—	112,500			4,500		220,500		—			—			225,000
Tax benefit from exercise of stock options	—		—	—			—		15,750		—			—			15,750
Expense of stock options	—		—	—			—		29,796		—			—			29,796
Treasury stock acquired	—		—	(2,575,000	)		—		—		(6,180,000	)		—			(6,180,000	)
Net income	—		—	—			—		—		—			6,576,982			6,576,982
Preferred stock dividends	—		—	—			—		—		—			(600,000	)		(600,000	)

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

Exercise of stock options and warrants	—		—	252,794			8,667		424,666		—			—			433,333

Tax benefit from exercise of stock options	—		—	—			—		7,292		—			—			7,292
Expense of stock options	—		—	—			—		134,431		—			—			134,431
Net loss	—		—	—			—		—					(4,336,025	)		(4,336,025	)
Preferred stock dividends	—		—	—			—		—		—			(600,000	)		(600,000	)

Balance at June 30, 2003	7,500	$	300	9,296,076		$	473,399	$	21,803,090	$	(6,180,000	)	$	4,640,725		$	20,737,514

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

F-7

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Business

Contango Oil & Gas Company (the “Company” or “Contango”) is a Houston-based, independent natural gas and oil company. The Company explores, develops, produces and acquires natural gas and oil properties primarily onshore in the Gulf Coast and offshore in the Gulf of Mexico. Contango’s entry into the natural gas and oil business began on July 1, 1999. Contango also owns a 10% partnership interest in a proposed LNG terminal in Freeport, Texas. The Company’s common stock commenced trading on the American Stock Exchange in January 2001 under the symbol “MCF”.

2. Summary of Significant Accounting Policies

F-8

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(continued)

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 June 30, 2003, as opposed to 100% of each ventures’ net assets as of June 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 $249,000, respectively, for the year-ended June 30, 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.

Prior Year Reclassification. Certain prior year amounts have been reclassified to conform to the current year presentation.

Recently Issued Accounting Standards. The FASB has recently issued five new pronouncements, Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS143”); Statement of Financial Accounting Standards No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets” (“SFAS144”); Statement of Financial Accounting Standards No. 146, “Accounting for Costs Associated with Exit and Disposal Activities” (“SFAS146”); Statement of Financial Accounting Standards No. 149 “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (“SFAS149”); and Statement of Financial Accounting Standards No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (“SFAS150”).

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. The Company considers that the cumulative effect of initially applying SFAS 143 is not material to the Consolidated Statement of Operations.

F-9

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(continued)

Activities related to the Company’s asset retirement obligation (“ARO”) during the year ended June 30, 2003 is a follows:

	Year Ended June 30, 2003

Initial ARO as of July 1, 2002	$	172,638
Liabilities incurred during period		9,666
Liabilities settled during period		—
Accretion expense		9,360

Balance of ARO as of June 30, 2003	$	191,664

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 had no effect 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 adoption of SFAS146 had no effect on the Company’s financial statements.

SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and hedging activities under SFAS 133. The amendments set forth in SFAS 149 require that contracts with comparable characteristics be accounted for similarly. SFAS 149 is generally effective for contracts entered into or modified after June 20, 2003 (with limited exceptions) and for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively only. The adoption of SFAS 149 is not expected to have a material effect on the Company’s financial statements.

SFAS150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. It is to be implemented by reporting the cumulative effect of a change in an accounting principle for financial instruments created before the issuance date of SFAS No. 150 and still existing at the beginning of the interim period of adoption. Restatement is not permitted. The Company does not expect the requirements of SFAS No. 150 to have a material impact on its consolidated financial position or results of operations.

F-10

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(continued)

On January 17, 2003, the FASB issued FIN 46, Consolidation of Variable Interest Entities, An Interpretation of ARB 51. The primary objectives of FIN 46 are to provide guidance on how to identify entities for which control is achieved through means other than through voting rights (variable interest entities or VIEs) and how to determine when and which business enterprise should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the equity investors do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity’s activities without receiving additional subordinated financial support from other parties. The Company must adopt FIN 46 for all variable interest entities acquired before January 31, 2003 on July 1, 2003. The Company does not anticipate the adoption of FIN 46 to have any effect on the Company’s financial statements.

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved natural gas and oil reserve quantities and the related present value of estimated future net cash flows therefrom (See “Supplemental Oil and Gas Disclosures”).

Revenue Recognition. Revenues from the sale of natural gas and oil produced are recognized upon the passage of title, net of royalties. Revenues from natural gas production are recorded using the sales method. When sales volumes exceed the Company’s entitled share, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. At June 30, 2002 and 2003, the Company had no overproduced imbalances.

Cash Equivalents. Cash equivalents are considered to be all highly liquid debt investments having an original maturity of three months or less. As of June 30, 2003, the Company had cash and cash equivalents of approximately $219,200. The carrying amounts approximated fair market value due to the short maturity of these instruments.

Marketable Equity Securities. All of the Company’s marketable securities relate to an investment in Cheniere Energy common stock. The Company has classified these securities as trading assets. Trading assets are stated at fair value, with gains or losses resulting from changes in fair value recognized currently in earnings under “Gain on Sale of Assets and Other”.

Net Income (Loss) per Common Share. Basic and diluted net income (loss) per common share have been computed in accordance with SFAS No. 128, “Earnings per Share”. Basic net income (loss) per common share is computed by dividing income (loss) attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. (see footnote 5 for the calculations of basic and diluted net income per common share).

Income Taxes. The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary

F-11

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(continued)

differences between the tax bases of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period.

Concentration of Credit Risk. Substantially all of the Company’s accounts receivable result from natural gas and oil sales or joint interest billings to a limited number of third parties in the natural gas and oil industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.

Consolidated Statements of Cash Flows. For the purpose of cash flows, the Company considers all highly liquid investments with a maturity date of three months or less when purchased to be cash equivalents. Significant transactions may occur which do not directly affect cash balances and, as such, are not disclosed in the Consolidated Statements of Cash Flows. Certain such non-cash transactions are disclosed in the Consolidated Statements of Shareholders’ Equity, including shares issued as compensation and issuance of stock options.

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

The Company has determined that the fair value method is preferable to the intrinsic value method previously applied. During the fiscal year-ended June 30, 2003 and 2002, the Company recorded a charge of $134,431 and $29,796 to general and administrative expense related to fiscal year 2003 and 2002 grants, respectively. Because compensation expense is recognized over a vesting period, the effect of applying the fair value method in the initial years of implementation may not be representative of the effects on net income (loss) that will be reported in future years.

F-12

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(continued)

3. Natural Gas and Oil Exploration Risk

The Company’s future financial condition and results of operations will depend upon prices received for its natural gas and oil production and the cost of finding, acquiring, developing and producing reserves. Substantially all of its production is sold under various terms and arrangements at prevailing market prices. Prices for natural gas and oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond its control. Other factors that have a direct bearing on the Company’s prospects are uncertainties inherent in estimating natural gas and oil reserves and future hydrocarbon production and cash flows, particularly with respect to wells that have not been fully tested and with wells having limited production histories; access to additional capital; changes in the price of natural gas and oil; availability and cost of services and equipment; and the presence of competitors with greater financial resources and capacity.

4. Liquidity

Management believes that cash on hand, anticipated cash flow from operations and availability under the Company’s bank credit facility (see footnote 8), will be adequate to satisfy planned capital expenditures to fund drilling activities and to satisfy general corporate needs over the next twelve months. The Company may continue to seek additional equity or other financing to fund the Company’s exploration program and to take advantage of other opportunities that may become available. The availability of such funds will depend upon prevailing market conditions and other factors over which the Company has no control, as well as the Company’s financial condition and results of operations. There can be no assurances that the Company will have sufficient funds available to finance its intended exploration and development programs or acquisitions. The Company’s exploration drilling program could be adversely affected if sufficient funds are unavailable.

F-13

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 for the fiscal years ended June 30, 2003 and 2002 is presented below:

	Year Ended June 30,
	2003								2002
	Net Loss			Shares		Per Share			Net Income		Shares	Per Share
	Net Loss			Shares		Per Share			Net Income		Shares	Per Share
Basic:
Net income (loss) attributable to common stock	$	(4,936,025	)	9,129,169		$	(0.54	)	$	5,976,982	10,841,665	$	0.55

Effect of Dilutive Securities:
Stock options and warrants		(a	)	(a	)					—	733,569
Series A preferred stock		(a	)	(a	)					200,000	1,000,000
Series B preferred stock		(a	)	(a	)					400,000	1,136,363

Diluted:
Net income (loss) attributable to common stock	$	(4,936,025	)	9,129,169		$	(0.54	)	$	6,576,982	13,711,597	$	0.48

(a)

Anti-dilutive.

6. Income Taxes

Actual income tax expense (benefit) differs from income tax expense (benefit) computed by applying the U.S. federal statutory corporate rate of 35 percent to pretax income (loss) as follows:

	Year Ended June 30,
	2003					2002
Provision (benefit) at statutory tax rate	$	(2,334,782	)	35.0	%	$	3,703,048		35.0	%
State income taxes		—		—			450,000		4.3	%
Federal benefit of state income taxes		—		—			(157,500	)	-1.5	%
Other		—		—			7,606		—

Income tax provision (benefit)	$	(2,334,782	)	35.0	%	$	4,003,154		37.8	%

F-14

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(continued)

The provision (benefit) for income taxes for the periods indicated are comprised of the following:

	Year-ended June 30,
	2003			2002
Current:
Federal	$	2,903,815		$	2,961,538
State		—			450,000

Total	$	2,903,815		$	3,411,538

Deferred:
Federal	$	(5,238,597	)	$	591,616
State		—			—

Total	$	(5,238,597	)	$	591,616

Tax Provision:
Federal	$	(2,334,782	)	$	3,553,154
State		—			450,000

Total	$	(2,334,782	)	$	4,003,154

The net deferred tax asset (liability) is comprised of the following:

	June 30,
	2003			2002
Deferred tax asset:
Capital loss carryforwards and other	$	1,784,638		$	—
Deferred tax liabilities:
Temporary basis differences in natural gas and oil properties and other		(1,216,614	)		(3,777,864	)

Net deferred tax asset (liability)	$	568,024		$	(3,777,864	)

Realization of the net deferred tax asset is dependent on the Company’s ability to generate taxable earnings in the future. During the fiscal year-ended June 30, 2003, the Company incurred approximately $4.2 million in capital loss related to hedging activities. Management believes that existing capital loss carryforwards comprising the deferred tax assets will reverse during periods in which the Company generates capital gains.

7. Purchase of Assets

Effective as of January 1, 2002, Contango entered into separate Asset Purchase Agreements with Juneau Exploration L.P. (“JEX”) and other individuals to purchase certain working and revenue interests of JEX and other individuals in its STEP properties. Contango paid approximately $12.9 million with cash on hand and increased availability under its credit facility. Mr. Juneau is the sole manager of JEX.

Effective January 1, 2002, Contango completed the acquisition from the Southern Ute Indian Tribe (“SUIT”) of additional ownership interests in its STEP properties at a cost of approximately $7.0 million, subject to purchase price adjustments. This acquisition was funded with cash on hand and increased availability under the Company’s credit facility.

F-15

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(continued)

Effective April 1, 2002, Contango completed an acquisition from JEX and other individuals of additional ownership interests in its STEP properties at a cost of approximately $3.4 million. This acquisition was funded with increased availability under the Company’s credit facility.

Effective July 1, 2002, Contango completed the acquisition from JEX and other individuals of additional ownership interests in its STEP properties at a cost of approximately $2.6 million. This acquisition was funded with availability under the Company’s credit facility.

8. Long-Term Debt

On June 29, 2001, Contango replaced its existing line of credit with a three year, secured, $20.0 million reducing revolving line of credit with Guaranty Bank, FSB, secured by the Company’s natural gas and oil reserves. The initial hydrocarbon borrowing base was set at $10.0 million, with the borrowing base to be redetermined semi-annually. In June 2003, the borrowing base was increased to $27.0 million in two tranches, and the final maturity was extended. Tranche A provides for a borrowing base of $24.5 million and matures on June 29, 2006. This amount reduces by $670,000 per month the first day of each month beginning July 1, 2003. Borrowings under Tranche A bear interest, at our option, at either (i) LIBOR plus two percent (2%) or (ii) the bank’s base rate plus one-fourth percent (1/4%) per annum. Additionally, we pay a quarterly commitment fee of three-eighths percent (3/8%) per annum on the average availability of Tranche A. Tranche B provides for a borrowing base of $2.5 million and matures on December 31, 2003. This amount reduces by $430,000 per month the first day of each month beginning July 1, 2003. Borrowings under Tranche B bear interest, at our option, at either (i) LIBOR plus four percent (4%) or (ii) the bank’s base rate plus one percent (1%) per annum. Additionally, we pay a quarterly commitment fee of one-half percent (1/2%) per annum on the average availability under Tranche B. As of June 30, 2003, the Company had $22,350,000 outstanding under Tranche A.

The Company’s long-term debt as of the periods indicated was as follows:

	June 30,
	2003			2002
Outstanding under line of credit	$	22,350,000		$	18,950,000
Current portion of long term-debt		(5,890,000	)		(1,330,000	)

Total long-term debt	$	16,460,000		$	17,620,000

As of June 30, 2003 and 2002, the Company was in compliance with its financial covenants, ratios and other provisions of the credit facility.

F-16

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(continued)

9. Commodity Price Hedges

Contango periodically enters into commodity derivative contracts. These contracts, which are usually placed with large energy pipeline and trading companies, major petroleum companies or financial institutions that the Company believes are minimal credit risks, may take the form of futures contracts, swaps or options. In June 1998, the FASB issued SFAS 133. In June 2000, the FASB issued SFAS 138, “Accounting for Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133”. SFAS 133, as amended, 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. The Company recognizes the changes in the derivative’s fair value in its income statement under gain (loss) from hedging activities. 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.

	Year Ended June 30,
	2003			2002
Mark-to-market reversal of prior period unrealized recognized gain (loss)	$	125,674		$	(888,400	)
Net cash received (paid) from swap, put and call settlements		(5,776,461	)		6,030,247
Mark-to-market loss unrealized		(58,171	)		(125,674	)

Gain (loss) from hedging activities	$	(5,708,958	)	$	5,016,173

The table below sets forth the Company’s pricing and notional volumes on open commodity derivative contracts as of June 30, 2003.

Contract Description	Term	Strike Price (1)		Quantity (1)
Natural gas puts owned	08/2003 – 10/2003	$	4.50	10,000/day
Natural gas puts owned	11/2003 – 12/2003	$	4.00	10,000/day
Natural gas calls sold	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 earnings. The Company’s derivative position as of June 30, 2003 had a mark-to-market loss of $58,171.

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. All of the Company’s recent historical hedging transactions have been carried out in the over-the-counter market with investment grade institutions. Accordingly, the terms of

F-17

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(continued)

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.

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

10. Commitments and Contingencies

Contango leases its office space and certain other equipment. As of June 30, 2003, minimum future lease payments are as follows:

Fiscal Year-ending June 30,
2004	$	72,913
2005		70,776
2006		64,640
2006		21,138
Thereafter		—

Total	$	229,467

The amount incurred under operating leases during the year-ended June 30, 2003 and 2002 was $88,404 and $80,009, respectively.

11. Shareholders’ Equity

Common Stock. Holders of the Company’s common stock are entitled to one vote per share on all matters to be voted on by shareholders and are entitled to receive dividends, if any, as may be declared from time to time by the Board of Directors of the Company. Upon any liquidation or dissolution of the Company, the holders of common stock are entitled to receive a pro rata share of all of the assets remaining available for distribution to shareholders after settlement of all liabilities and liquidating preferences of preferred stockholders.

On March 28, 2002, Contango repurchased 2,575,000 shares of Contango common stock owned by the Southern Ute Indian Tribe doing business as the Southern Ute Indian Tribe Growth Fund (“SUIT Growth Fund”) for $6,180,000. This share repurchase represents a 22% reduction in Contango’s outstanding common shares. The SUIT Growth Fund originally purchased these securities in private placements during June and August 2000. In addition, the Company cancelled a warrant held by the SUIT Growth Fund to purchase 125,000 shares of its common stock at $2.00 per share and options to purchase 17,500 shares of its common stock at prices between $2.70 and $5.87 per share. In connection with these transactions, Robert J. Zahradnik, Director of Operations of the SUIT Growth Fund and a Contango director, tendered his resignation as a director to the Company’s Board of Directors.

Preferred Stock. The Company’s Board of Directors has authorized 5,000,000 shares of preferred stock, of which 2,500 shares of Series A convertible preferred stock and 5,000 shares of Series B convertible preferred stock were issued and outstanding as of June 30, 2003 and 2002, respectively.

F-18

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(continued)

12. Stock Options

In September 1999, the Company established the Contango Oil & Gas Company 1999 Stock Incentive Plan (the “Option Plan”). Under the Option Plan, the Company may issue up to 2,500,000 shares of common stock with an exercise price of each option equal to or greater than the market price of the Company’s common stock on the date of grant, but in no event less than $2.00 per share. The Company may grant key employees both incentive stock options intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that are not qualified as incentive stock options. Stock option grants to non-employees, such as directors and consultants, can only be stock options that are not qualified as incentive stock options. Options generally expire after five or ten years. The vesting schedule varies, but vesting generally occurs over a two-year period (1/3 immediately, 1/3 one year from the date of grant and 1/3 two years from the date of grant). As of June 30, 2003, options under the Option Plan to acquire 755,500 shares of common stock have been granted at prices between $2.00 and $5.87 per share and were outstanding.

In addition to grants made under the Option Plan, the Company has granted options to purchase common stock outside the Option Plan. These options generally expire after five years. The vesting schedule varies, but vesting generally occurs either (i) immediately, (ii) over a two-year period (1/3 immediately, 1/3 one year from the date of grant and 1/3 two years from the date of grant), or (iii) under a vesting schedule that is tied to the payout and rate of return on specific projects for which the option was granted. As of June 30, 2003, options to acquire 524,834 shares of common stock have been granted at prices between $2.00 and $5.87 per share and were outstanding.

A summary of the status of the plans as of June 30, 2003 and 2002, and changes during the fiscal years then ended, is presented in the table below:

	Year Ended June 30,
	2003					2002
	Shares Under Options			Weighted Average Exercise Price		Shares Under Options			Weighted Average Exercise Price



Outstanding, beginning of year		1,210,334		$	2.85		1,015,334		$	2.89
Granted		292,500		$	3.35		255,000		$	2.60
Exercised		(130,001	)	$	2.27		(37,500	)	$	2.00
Cancelled		(92,499	)	$	3.43		(22,500	)	$	3.40

Outstanding, end of year		1,280,334		$	2.98		1,210,334		$	2.85

Exercisable, end of year		851,667		$	2.97		795,334		$	2.76

Available for grant, end of year		1,597,749					1,794,750

Weighted average fair value of options granted during the year (1)	$	1.11				$	0.69

(1)

The fair value of each option is estimated as of the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants during the years ended June 30, 2003 and 2002, respectively: (i) risk-free interest rate of 3.14 percent and 3.98 percent; (ii) expected lives of five years for the Option Plan and other options; (iii) expected volatility of 27 percent and 20 percent; and (iv) expected dividend yield of zero percent.

F-19

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(continued)

The following table summarizes information about options that were outstanding at June 30, 2003:

	Options Outstanding				Options Exercisable
Range of Exercise Price	Number of Shares Under Outstanding Options	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Number of Shares Under Exercisable Options	Weighted Average Exercise Price




$2.00 – $2.99	574,334	3.5	$	2.14	388,334	$	2.05
$3.01 – $3.99	412,500	4.0	$	3.16	245,500	$	3.15
$4.01 – $4.99	278,500	3.0	$	4.30	202,833	$	4.33
$5.01 – $5.99	15,000	2.6	$	5.56	15,000	$	5.56

	1,280,334	3.5	$	2.98	851,667	$	2.97

Effective July 1, 2001, the Company changed it method of accounting for employee stock-based compensation to the fair value method prescribed in SFAS No. 123, “Accounting for Stock-Based Compensation” (see Footnote 2).

All employee stock options grants are expensed over the stock options 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. During the fiscal year-ended June 30, 2003 and 2002, the Company recorded an expense of $134,431 and $29,796, respectively, related to the fiscal year 2003 and 2002 employee stock options.

13. Warrants

As of June 30, 2003, the Company had issued and outstanding warrants to purchase 1,640,185 shares of the Company’s common stock. All warrants were exercisable at June 30, 2003. The Company has reserved an equal number of shares of common stock for issuance upon the exercise of its outstanding warrants. Warrants issued by the Company do not confer upon the holders any voting or other rights of a shareholder of the Company. A summary of the Company warrants as of June 30, 2003 and 2002, and changes during the fiscal years then ended, is presented in the table below:

	Year Ended June 30,
	2003				2002
	Number of Shares Under Outstanding Warrants		Weighted Average Exercise Price		Number of Shares Under Outstanding Warrants		Weighted Average Exercise Price




Outstanding, beginning of year	1,840,185		$	2.14	2,040,185		$	2.13
Exercised	(200,000	)	$	2.00	(75,000	)	$	2.00
Cancelled	—		$	—	(125,000	)	$	2.00

Outstanding, end of year	1,640,185		$	2.16	1,840,185		$	2.14

F-20

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(continued)

The following table summarizes information about warrants that were outstanding at June 30, 2003:

	Warrants Outstanding and Exercisable
Exercise Price	Number of Shares Under Outstanding Warrants	Weighted Average Remaining Contractual Life
$2.00	1,515,185	1.4
$4.12	125,000	2.4

	1,640,185	1.5

14. Investment in LNG

In June 2002, the Company paid $750,000 to Cheniere Energy, Inc. (Cheniere”) for an option to acquire a 10% interest in a proposed liquefied natural gas (“LNG”) receiving terminal in Freeport, Texas. In March 2003, Contango exercised its option with Cheniere to acquire a 10% interest in Freeport LNG Development L.P., the limited partnership formed to develop an LNG receiving terminal in Freeport, Texas. Additionally, Cheniere granted to Contango warrants to purchase 300,000 shares of Cheniere common stock in connection with the formation of Freeport LNG Development L.P. Contango will pay Cheniere a total price of $2.33 million over time for its ownership in LNG. As of June 30, 2003, Contango has paid Cheniere $850,000, including the $750,000 previously invested. An additional $1.08 million is being paid monthly over the next eleven months. The balance of $400,000 will be paid upon receipt of project approval from the Federal Energy and Regulatory Commission.

In June 2003, Contango exercised a warrant to purchase 150,000 shares of Cheniere common stock. In August 2003, Contango sold the 150,000 shares of Cheniere common for a net gain of $577,400. At June 30, 2003, the 150,000 shares of Cheniere common stock had a mark-to-market valuation of $451,500. Contango still holds a warrant to purchase an additional 150,000 shares of Cheniere common stock.

15. Subsequent Events

In September 2003, Contango exercised its warrant to purchase an additional 150,000 shares of Cheniere common stock at $2.50 per share, or $375,000.

On September 12, 2003, Contango completed the sale of certain non-core reserves in Brooks County, Texas for $5.0 million. Proved reserves were 1.5 Bcfe and accounted for approximately $5.0 million of the Company’s present value discounted at 10% per annum as of June 30, 2003. This sale was effective July 1, 2003.

F-21

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

The following disclosures provide unaudited information required by SFAS No. 69, “Disclosures About Oil and Gas Producing Activities”.

Costs Incurred. The following table sets forth the costs incurred in natural gas and oil property acquisition, exploration and development activities for the fiscal years ended June 30, 2003 and 2002:

	Year Ended June 30,
	2003		2002
Property acquisition costs:
Unproved	$	972,658	$	1,063,204
Proved		2,602,551		23,449,488
Exploration costs		19,194,281		7,138,690

Total costs incurred	$	22,769,490	$	31,651,382

Natural Gas and Oil Reserves. Proved reserves are estimated quantities of natural gas and oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that reasonably can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved natural gas and oil reserve quantities at June 30, 2003 and 2002, and the related discounted future net cash flows before income taxes are based on estimates prepared by W.D. Von Gonten & Co., petroleum engineering. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.

The Company’s net ownership interests in estimated quantities of proved natural gas and oil reserves and changes in net proved reserves as of June 30, 2003 and 2002, all of which are located in the continental United States, are summarized below:

	As of June 30, 2003				As of June 30, 2002
	Oil and Condensate		Natural Gas		Oil and Condensate		Natural Gas
	Oil and Condensate		Natural Gas		Oil and Condensate		Natural Gas
	(MBbls)		(MMcf)		(MBbls)		(MMcf)
Proved developed and undeveloped reserves:
Beginning of year	590		24,399		335		16,134
Purchases of natural gas and oil properties	24		1,002		275		11,410
Sale of reserves	—		—		(9	)	(11	)
Discoveries	89		1,088		138		5,661
Recoveries and revisions	(169	)	749		37		(1,812	)
Production	(139	)	(6,016	)	(186	)	(6,983	)

End of year	395		21,222		590		24,399

Proved developed reserves at end of year	395		21,039		590		24,399

F-22

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Standardized Measure. The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved natural gas and oil reserves as of June 30, 2003 and 2002 are shown below:

	As of June 30,
	2003			2002
Future cash flows	$	129,383,905		$	99,854,148
Future operating expenses		(34,087,698	)		(27,032,959	)
Future development costs		(383,975	)		(119,572	)
Future income tax expenses		(24,244,639	)		(17,506,926	)

Future net cash flows		70,667,593			55,194,691
10% annual discount for estimated timing of cash flows		(18,108,003	)		(14,390,805	)

Standardized measure of discounted future net cash flows	$	52,559,590		$	40,803,886

Future cash flows are computed by applying fiscal year-end prices of natural gas and oil to year-end quantities of proved natural gas and oil reserves. Future operating expenses and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved natural gas and oil reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

Future income taxes are based on year-end statutory rates, adjusted for tax basis and applicable tax credits. A discount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s natural gas and oil properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates of natural gas and oil producing operations.

F-23

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Change in Standardized Measure. Changes in the standardized measure of future net cash flows relating to proved natural gas and oil reserves are summarized below:

	Year Ended June 30,
	2003			2002
Changes due to current year operation:
Sales of natural gas and oil, net of natural gas and oil operating expenses	$	(28,182,672	)	$	(19,997,454	)
Extensions and discoveries		5,733,620			14,197,323
Net change in prices and production costs		29,257,508			(6,906,532	)
Change in future development costs		89,596			309,046
Revisions of quantity estimates		(762,108	)		(3,228,270	)
Sale of reserves		—			(146,669	)
Accretion of discount		5,334,922			4,262,580
Change in the timing of production rates and other		1,176,504			(3,510,030	)
Purchases of natural gas and oil properties		3,630,556			25,743,424
Changes in income taxes		(4,522,222	)		(3,066,137	)

Net change		11,755,704			7,657,281
Beginning of year		40,803,886			33,146,605

End of year	$	52,559,590		$	40,803,886

F-24