For the Fiscal Year Ended June 30, 2004
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-K

 


 

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

SECURITIES EXCHANGE ACT OF 1934

 

For the Fiscal Year Ended June 30, 2004

 

Commission file number 000-24971

 


 

CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)

 


 

Delaware   95-4079863

(State or other jurisdiction of

incorporation or organization)

 

(IRS Employer

Identification No.)

 

3700 Buffalo Speedway, Suite 960

Houston, Texas 77098

(Address of principal executive offices)

 

(713) 960-1901

(Issuer’s telephone number)

 

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

 

Common Stock, Par Value $0.04 per share   American Stock Exchange

 


 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and 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-K or any amendment to this Form 10-K.  ¨

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

 

The aggregate market value of the voting common equity held by non-affiliates computed by reference to the average bid and asked price of such common equity at the close of business on September 15, 2004, was $48,054,646. As of September 15, 2004, there were 12,977,366 shares of the issuer’s common stock outstanding.

 

Documents Incorporated by Reference

 

Items 10, 11, 12, 13 and 14 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 10, 11, 12, 13 and 14 of this report, which will appear in the definitive proxy statement, is incorporated by reference into this Form 10-K.

 



Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

ANNUAL REPORT ON FORM 10-K FOR THE FISCAL ENDED JUNE 30, 2004

 

TABLE OF CONTENTS

 

         Page

PART I     

Item 1.

  Business     
   

Overview

   1
   

Our Strategy

   1
   

Exploration Alliances with JEX, Alta Resources, Ameritex and Coastline

   2
   

Domestic Onshore Exploration and Properties

   3
   

International Onshore Exploration and Properties

   4
   

Offshore Gulf of Mexico Exploration Joint Ventures

   4
   

Offshore Properties

   5
   

Freeport LNG Development, L.P.

   6
   

Contango Venture Capital Corporation

   7
   

Marketing and Pricing

   7
   

Competition

   8
   

Governmental Regulations

   8
   

Employees

   10
   

Directors and Executive Officers

   11
   

Corporate Offices

   12
   

Code of Ethics

   12
   

Risk Factors

   13

Item 2.

  Description of Properties     
   

Production, Prices and Operating Expenses

   20
   

Development, Exploration and Acquisition Capital Expenditures

   20
   

Drilling Activity

   21
   

Exploration and Development Acreage

   21
   

Productive Wells

   22
   

Natural Gas and Oil Reserves

   22

Item 3.

  Legal Proceedings    23

Item 4.

  Submission of Matters to a Vote of Security Holders    23
PART II     

Item 5.

  Market for Registrant’s Common Equity and Related Stockholder Matters    23

Item 6.

  Selected Financial Data    25

Item 7.

  Management’s Discussion and Analysis of Financial Condition and Results of Operations     
   

Overview

   26
   

Results of Operations

   27
   

Capital Resources and Liquidity

   30
   

Contractual Obligations

   31
   

Credit Facility

   31
   

Critical Accounting Policies

   31

Item 7a.

  Quantitative and Qualitative Disclosure about Market Risk    36

Item 8.

  Financial Statements and Supplementary Data    36

Item 9.

  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure    36

Item 9a.

  Controls and Procedures    36

Item 9b.

  Other Information    37
PART III     

Item 10.

  Directors and Executive Officers of the Registrant    37

Item 11.

  Executive Compensation    37

Item 12.

  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters    37

Item 13.

  Certain Relationships and Related Transactions    37

Item 14.

  Principal Accountant Fees and Services    37
PART IV     

Item 15.

  Exhibits, Financial Statement Schedules and Reports on Form 8-K    37

 

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Cautionary Statement About Forward-Looking Statements

 

Some of the statements made in this Form 10-K may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words and phrases “should be”, “will be”, “believe”, “expect”, “anticipate”, “estimate”, “forecast”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. These include such matters as:

 

  Our financial position

 

  Business strategy and budgets

 

  Anticipated capital expenditures

 

  Drilling of wells

 

  Natural gas and oil reserves

 

  Timing and amount of future production of natural gas and oil

 

  Operating costs and other expenses

 

  Cash flow and anticipated liquidity

 

  Prospect development

 

  Property acquisitions and sales

 

  Hedging results

 

  Development and financing of our LNG receiving terminal

 

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

 

  Low and/or declining prices for natural gas and oil

 

  Natural gas and oil price volatility

 

  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

 

  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

 

  Weather

 

  Availability and cost of material and equipment

 

  Delays in anticipated start-up dates

 

  Actions or inactions of third-party operators of our properties

 

  Ability to find and retain skilled personnel

 

  Strength and financial resources of competitors

 

  Federal and state regulatory developments and approvals

 

  Environmental risks

 

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  Worldwide economic conditions

 

  Operational and financial risks associated with foreign exploration and production

 

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

 

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

 

You should not unduly rely on these forward-looking statements in this Form 10-K, as they speak only as of the date of this Form 10-K. Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this Form 10-K or to reflect the occurrence of unanticipated events. See the information under the heading “ Risk Factors” in this Form 10-K 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.

 

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All references in this Form 10-K 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-K 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.contango.com. Our Annual Reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our Website as soon as reasonably practicable after we file or furnish them to the Securities and Exchange Commission.

 

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, both onshore Gulf Coast and offshore in the Gulf of Mexico. Our primary source of natural gas and oil production currently is in south Texas. We also own a 10% partnership interest in Freeport LNG Development, L.P., which is developing a 1.5 Bcf per day LNG receiving terminal in Freeport, Texas, and have a 32% interest in Contango Capital Partnership Management, LLC, which was formed to invest in the alternative energy venture capital market.

 

As of June 30, 2004, we owned approximately 17.4 Bcfe of total proved reserves, compared to 23.6 Bcfe as of June 30, 2003. As of June 30, 2004 and 2003, approximately 99% and 97% 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, 2004 was approximately $59.8 million, compared to $69.6 million as of June 30, 2003.

 

Total revenues and EBITDAX for the year ended June 30, 2004 were $27.7 million and $29.0 million, respectively. For the year ended June 30, 2003, total revenues and EBITDAX were $28.2 million and $20.9 million, respectively. We define EBITDAX as earnings before interest, income taxes, depreciation, depletion and amortization, impairment expense and expensed exploration expenditures, including gains (losses) from hedging activities, and sale of assets and other. See Item 6. “Selected Financial Data” for more information about the calculation of EBITDAX and its uses. Average net daily production for the year ended June 30, 2004 was 11.8 MMcf of natural gas and 272 barrels of oil per day, compared to 16.5 MMcf of natural gas and 380 barrels of oil per day for the year ended June 30, 2003.

 

Our Strategy

 

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

 

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

 

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Negotiated acquisitions of proved properties. We continue to seek negotiated producing property acquisitions based on our view of the pricing cycles of natural gas and oil and available exploitation opportunities of probable and possible reserves. Since January 1, 2002, we have acquired approximately 14.0 Bcfe of proved developed producing reserves of natural gas and oil for approximately $26.0 million.

 

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

 

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

 

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

 

Diversified energy investments. While our core focus is the domestic exploration and production business, we will continue to seek opportunities that may include foreign exploration prospects or investments related to new and developing energy sources such as LNG and alternative energy (see below).

 

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 22% of our common stock. In addition, our alliance partners co-invest in prospects that they recommend to us.

 

Exploration Alliances with JEX, Alta Resources, Ameritex and Coastline

 

Alliance with JEX. JEX was our first alliance partner. Under our agreement with JEX, JEX generates natural gas and oil prospects and evaluates exploration prospects generated by others. 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. In the Gulf of Mexico, JEX brings offshore exploration prospects directly to our affiliated companies, Republic Exploration, LLC and Contango Offshore Exploration, LLC (see “Offshore Gulf of Mexico Exploration Joint Ventures” below).

 

If JEX recommends an onshore prospect to Contango, we pay the lease and seismic costs, and JEX generally pays the remaining costs of generating and preparing a prospect to drill ready status. When drilling begins on a prospect, we are obligated to assign to the JEX geoscientists an overriding royalty interest equal to 3 1/3% of our working interest in the prospect. In addition, when our revenues from prospects we invest in under the agreement, net of taxes, royalties and other expenses equals our capital expenditure related to the exploration and development of the prospects on a well-by-well basis, JEX is entitled to an assignment of 25% of our working interest in the well.

 

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.

 

Offshore prospects are typically generated by our partially owned subsidiaries, Republic Exploration LLC and Contango Offshore Exploration LLC. JEX is the managing partner of both entities. See “Offshore Gulf of Mexico Exploration Joint Ventures” below.

 

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

 

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

 

Alliance with Coastline. Coastline is a private company engaged in domestic, onshore natural gas and oil exploration and production. In late 2003, we entered into our original agreement with Coastline to explore for and develop natural gas and oil prospects in Kenedy County, Texas. Our arrangement with Coastline generally provides for us to pay all leasehold costs, with Coastline generally receiving a negotiated overriding royalty interest and a carried working interest to casing point.

 

Domestic Onshore Exploration and Properties

 

JEX Activities

 

JEX was our first alliance partner. Between May 2000 and March 2004, we drilled 49 wells with JEX on our south Texas properties in Jim Hogg and Brooks Cos., Texas, resulting in 34 successes. We have no further drilling plans on this acreage.

 

While JEX continues a limited onshore exploration effort for us, JEX’s principle activity is the exploration management of our affiliated offshore Gulf of Mexico exploration companies. See “Offshore Gulf of Mexico Exploration and Joint Ventures”.

 

Alta Resources Activities

 

In October 2003, Contango and Alta Resources completed a 3-D seismic shoot covering approximately 40 square miles in southern Duval County, Texas. The net cost to us was approximately $1.7 million. Two Queen City prospects have been successfully drilled and commenced production in September 2004. Two additional shallow prospects have been identified and are expected to be drilled prior to calendar year end 2004.

 

We recently participated with Alta Resources in an unsuccessful exploratory Frio well located in Matagorda County, Texas. The dry hole cost was approximately $1.4 million, of which our share was $0.7 million.

 

We are currently participating with Alta in an exploratory Queen City well in Jim Hogg County, Texas. Our 45% share of the dry hole cost is estimated at $0.4 million. In addition, we have agreed to participate in an exploratory well in Bandera County, Texas. We expect to drill this prospect by mid-year 2005. Our 50% share of the dry hole cost is estimated at $0.6 million.

 

Ameritex Activities

 

In February 2004, we entered into an exploration agreement with Ameritex. Ameritex has currently identified eight prospect areas. Amertiex has successfully drilled an 11,400-foot Wilcox test in one prospect area in Zapata County, Texas. We have a 14% net revenue interest in this well. Another Wilcox test is planned for a second prospect area in Zapata County, Texas next year. Our 18.8% share of the dry hole cost is estimated at approximately $0.8 million. Prospect generation is continuing on identified prospect areas.

 

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Coastline Activities

 

In September 2004, we entered into an agreement with Coastline to generate prospects in Jim Hogg County, Texas using available 3-D seismic data. Contango has agreed to reimburse Coastline $100,000 for geological and geophysical costs. If drillable prospects are identified, we will pay all of the prospect leasehold costs and carry Coastline on a portion of the drilling costs on a specified number of wells. In addition, Coastline will receive an overriding royalty interest.

 

International Onshore Exploration and Properties

 

In March 2004, Contango and Texas Petroleum Investment Company agreed to pursue an oil exploration prospect in the Aquitaine Basin in southwestern France. The initial well was drilled to approximately 10,500 feet and was a dry hole. The cost of this well was approximately $4.0 million, with Contango’s 20% dry hole cost of $0.8 million. We have no future plans in France.

 

Offshore Gulf of Mexico Exploration Joint Ventures

 

Contango directly and through affiliated companies conducts exploration activities in the Gulf of Mexico. Currently, Contango and its affiliates have interests in 42 offshore leases. See “Offshore Properties” below for additional information on our offshore properties.

 

Contango owns an equity interest in Republic Exploration and Contango Offshore Exploration, formed for the purpose of generating exploration opportunities in the Gulf of Mexico. These companies have collectively licensed approximately 4,000 blocks of 3-D seismic data and have focused on identifying prospects, acquiring leases at federal and state lease sales and then selling the prospects to third parties, subject to timed drilling obligations plus retained reversionary interests in favor of Republic Exploration and Contango Offshore Exploration. 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. JEX is the managing member of Republic Exploration and Contango Offshore Exploration.

 

Republic Exploration LLC. Contango invested approximately $6.7 million in Republic Exploration in August 2000 for a 33.3% ownership interest. The other members of Republic Exploration are JEX, its managing member, and a privately held seismic company. Both have comprehensive offshore experience. Republic Exploration holds a non-exclusive license to approximately 1,700 blocks of 3-D seismic data in the shallow waters of the Gulf of Mexico. This data is used to identify, acquire and exploit natural gas and oil prospects. All leases owned by Republic Exploration are subject to a 3.3% overriding royalty interest in favor of the JEX exploration team. See “Offshore Properties” below for more information on Republic Exploration’s offshore properties.

 

Contango Offshore Exploration LLC. Contango purchased a 66.7% interest in Contango Offshore Exploration in September 2002. JEX is the only other member and acts as the managing member. Contango Offshore Exploration’s activities will be focused on identifying and purchasing prospects in the Gulf of Mexico and selling them to third parties, retaining a reversionary interest. Contango Offshore Exploration has invested approximately $13.6 million to acquire and reprocess 2,294 blocks of 3-D seismic data and to acquire leases in the Gulf of Mexico. All leases will be subject to a 3.3% overriding royalty interest in favor of the JEX exploration team. See “Offshore Properties” below for additional information on Contango Offshore Exploration’s properties.

 

Current Activities. On March 17, 2004, Republic Exploration and Contango Offshore Exploration bid on 37 blocks offered at the Central Gulf of Mexico Lease Sale #190 held in New Orleans and were awarded 24 blocks. Each of these blocks is located on the shelf of the Gulf of Mexico in water depths of less than 200 meters. Contango currently own interests, both directly and indirectly through its affiliates, in 42 federal lease blocks in the Gulf of Mexico.

 

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In May 2003, Contango and Republic Exploration farmed out Eugene Island 113B. This well is currently drilling. Republic Exploration and Contango Offshore Exploration recently farmed out five lease blocks, Vermilion 73, West Cameron 174, Eugene Island 76, Vermilion 154 and Main Pass 221. An exploratory well to test a deep sand on Vermilion 73 was unsuccessfully drilled earlier this year. A shallower formation is expected to be drilled later this year. West Cameron 174, Eugene Island 76 and Main Pass 221 are expected to be drilled in the 2004-2005 timeframe. A timetable for drilling Vermilion 154 has not been determined at this time. Republic Exploration has sold the NE/4 of West Cameron 133. The remainder is available for farm-out. Contango Offshore Exploration has granted seismic options on East Breaks 369 and 370.

 

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

 

Offshore Properties

 

The following table sets forth the interests owned by Contango and related entities in the Gulf of Mexico as of September 15, 2004:

 

Area/Block


   WI

    NRI

    Acquired

  

Status


Contango Oil & Gas Company:

                     

Brazos 436

   13.6 %   10.8 %   Jul-00    Sold

East Cameron 107

   33.8 %   27.0 %   May-01    Available for farm-out

Eugene Island 113B

   (2 )   (2 )   May-01    Farmed-out, drilling

 

Area/Block


   WI

    NRI

    Acquired

  

Status


Republic Exploration (1):

                     

East Cameron 107

   66.2 %   53.0 %   May-01    Available for farm-out

Eugene Island 113B

   (2 )   (2 )   May-01    Farmed-out, drilling

West Delta 36

   100.0 %   80.0 %   May-02    Available for farm-out

Vermilion 73

   (3 )   (3 )   Jul-02    Farmed-out; drilling expected 4Q2004

West Cameron 174

   (4 )   (4 )   Jun-03    Farmed out; drilling expected 1Q2005

High Island 113

   100.0 %   80.0 %   Sep-03    Available for farm-out

South Timbalier 191

   50.0 %   40.0 %   May-04    Available for farm-out

Vermilion 36

   100.0 %   80.0 %   May-04    Available for farm-out

Vermilion 109

   100.0 %   80.0 %   May-04    Available for farm-out

Vermilion 134

   100.0 %   80.0 %   May-04    Available for farm-out

West Cameron 179

   100.0 %   80.0 %   May-04    Available for farm-out

West Cameron 185

   100.0 %   80.0 %   May-04    Available for farm-out

West Cameron 200

   100.0 %   80.0 %   May-04    Available for farm-out

West Delta 18

   100.0 %   80.0 %   May-04    Available for farm-out

West Delta 33

   100.0 %   80.0 %   May-04    Available for farm-out

West Delta 34

   100.0 %   80.0 %   May-04    Available for farm-out

West Delta 43

   100.0 %   80.0 %   May-04    Available for farm-out

Ship Shoal 220

   50.0 %   40.0 %   May-04    Available for farm-out

South Timbalier 240

   50.0 %   40.0 %   May-04    Available for farm-out

Eugene Island 76

   (4 )   (4 )   Jul-04    Farmed out; drilling expected 1Q2005

South Marsh Island 247

   (5 )   (5 )   Jul-04    Subject to farm-out option

Vermilion 130

   100.0 %   80.0 %   Jul-04    Available for farm-out

West Cameron 80

   100.0 %   80.0 %   Jul-04    Available for farm-out

West Cameron 133

   (6 )   (6 )   May-04    NE/4 sold, remainder available for farm-out

West Cameron 167

   100.0 %   80.0 %   Jul-04    Available for farm-out

Vermilion 154

   (7 )   (7 )   Jul-04    Farmed out; drilling schedule undetermined

 

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Area/Block


   WI

    NRI

    Acquired

  

Status


Contango Offshore Exploration (1):

                     

Vermilion 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

   100.0 %   80.0 %   Nov-03    Available for farm-out

East Breaks 283

   100.0 %   80.0 %   Nov-03    Available for farm-out

East Breaks 369

   (8 )   (8 )   Nov-03    Subject to seismic option

East Breaks 370

   (8 )   (8 )   Nov-03    Subject to seismic option

South Timbalier 191

   50.0 %   40.0 %   May-04    Available for farm-out

Grand Isle 63

   100.0 %   80.0 %   Jun-04    Available for farm-out

Grand Isle 72

   100.0 %   80.0 %   Jun-04    Available for farm-out

Grand Isle 73

   100.0 %   80.0 %   Jun-04    Available for farm-out

Ship Shoal 220

   50.0 %   40.0 %   May-04    Available for farm-out

South Timbalier 240

   50.0 %   40.0 %   May-04    Available for farm-out

Main Pass 221

   (9 )   (9 )   Jul-04    Farmed out; drilling expected 2005

Viosca Knoll 118

   100.0 %   80.0 %   May-04    Available for farm-out

Vermilion 154

   (7 )   (7 )   Jul-04    Farmed out; drilling schedule undetermined

Ship Shoal 358, A-3 well

   10.0 %   7.7 %   May-04    Producing

Area/Block


   WI

    NRI

    Acquired

  

Status


Magnolia Offshore Exploration (1):

                     

Ship Shoal 155

   100.0 %   80.0 %   May-02    Available for farm-out

Viosca Knoll 75

   100.0 %   80.0 %   May-02    Available for farm-out

(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. Magnolia Offshore Exploration does not intend to acquire any additional leases.
(2) Contango (33.75%) and Republic Exploration (66.25%) will collectively have a 5.0% overriding royalty interest (1.7% and 3.3%, respectively).
(3) Republic Exploration has a 5% of 8/8 ORRI before payout. At payout, Republic Exploration has the option, but not the obligation, to convert the ORRI to a 25% WI (20% NRI).
(4) Republic Exploration has a 5% of 8/8 ORRI in the lease before payout. Upon payout, Republic Exploration will elect to either (i) escalate its ORRI in the lease from 5% to 8 1/3% of 8/8 or (ii) convert the 5% ORRI to a 25% WI (20% NRI).
(5) If optionee elects to drill a well on this block, it will be subject to the terms set forth under (3) above.
(6) Republic Exploration has no interest in the NE/4 of the block. The remainder of the block, which is available for farm-out, is owned by Republic Exploration 100% WI (80% NRI).
(7) Republic Exploration and Contango Offshore Exploration will split a 25% back-in WI after payout.
(8) Contango Offshore Exploration has granted a seismic option, which expires 10/2004; thereafter, optionee must either commit to drill a well on the block or forfeit the right to earn an interest.
(9) Contango Offshore Exploration has a 5% of 8/8 ORRI in lease before payout. Upon payout, Contango Offshore Exploration’s ORRI will escalate to 7.2% of 8/8.

 

Freeport LNG Development, L.P.

 

In March 2003, we exercised an option to purchase from Cheniere Energy, Inc. a 10% limited partnership interest in Freeport LNG Development, L.P. (“Freeport LNG Project” and “Freeport LNG”), a limited partnership formed to develop a 1.5 billion cubic feet per day LNG receiving terminal in Freeport, Texas. The $2.3 million cost to acquire our 10% limited partnership interest was paid as of June 30, 2004, including a final payment of $0.4 million paid in June 2004 upon receipt of Federal Energy Regulatory Commission (“FERC”) approval for the project.

 

In June 2003, Dow Chemical Company signed an agreement with Freeport LNG for the potential long-term use of the receiving terminal. Under the agreement, Dow had regasification rights to 500 million cubic feet per day beginning with commercial start-up of the facility expected in 2007. On March 1, 2004, Freeport

 

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LNG and Dow entered into a 20-year Terminal Use Agreement providing for a firm commitment by Dow for the use of 250 million cubic feet per day of regasification capacity and an option to acquire an additional 250 million cubic feet per day of regasification capacity. Dow has exercised its rights to the full 500 million cubic feet per day of regasification capacity.

 

In June 2004, FERC issued an Order under Section 3 of the Natural Gas Act authorizing Freeport LNG to site, construct and operate a liquefied natural gas receiving terminal in Freeport, Texas. In September 2004, FERC extended until June 2009 the time Freeport LNG has to put the LNG terminal into service.

 

In July 2004, Freeport LNG finalized its transaction with ConocoPhillips for the construction and use of the proposed liquefied LNG receiving terminal in Freeport, Texas. ConocoPhillips acquired 1.0 billion cubic feet per day of regasification capacity in the terminal, purchased a 50% interest in the general partner managing the Freeport LNG Project and will provide substantial construction funding to the venture. This construction funding will be non-recourse to Contango. Freeport LNG and ConocoPhillips are negotiating the engineering, procurement and construction contract for the terminal. The current management of Freeport LNG will remain in place and will oversee the commercial activities of the partnership, while ConocoPhillips will manage the construction of the facility and oversee its operations.

 

Although we believe that a majority of the Freeport LNG financing will be provided by construction funding through ConocoPhillips, we anticipate that we will, from time-to-time, be required to provide funds to the project. Moreover, if the plant’s capacity were to be expanded beyond its current anticipated 1.5 Bcf per day, we would likely be required to provide our pro rata 10% equity participation to help secure the funds required for expanding the plant’s capacity.

 

Contango Venture Capital Corporation

 

In June 2004, our wholly owned subsidiary, Contango Venture Capital Corporation, acquired a 32% interest in Contango Capital Partnership Management, LLC. Contango Capital Partnership Management was formed by us and other investors to invest in the energy venture capital market with a focus on domestically sourced, environmentally preferred energy technologies and to expose us to leading edge technologies and opportunities in alternative energy markets. Our cash contribution of $0.5 million is being used to fund the initial overhead for the sourcing and management of energy venture capital investments. We hold two of six seats on the board of managers of Contango Capital Partnership Management, LLC.

 

In July 2004, Contango Venture Capital Corporation committed to invest $0.1 million as a limited partner in Trulite, L.P. Trulite, L.P. is a developer of lightweight hydrogen generators for fuel cell systems. The general partner of Trulite, L.P. is Contango Capital Partnership Management LLC. Contango Capital Partnership Management LLC assisted Trulite, L.P. in raising $0.5 million of seed equity. The proceeds of this initial financing will be used to develop Trulite, L.P.’s technology and to fund general operations.

 

Marketing and Pricing

 

The Company currently derives its revenue principally from the sale of natural gas. As a result, the Company’s revenues are determined, to a large degree, by prevailing natural gas prices. The Company currently sells the majority of its natural gas on the open market at prevailing market prices. The market price for natural gas is dictated by supply and demand, and the Company cannot accurately predict or control the price it receives for its natural gas.

 

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

 

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

 

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

 

  The level of LNG imports

 

  Domestic and foreign governmental regulations

 

  Potential price controls

 

From time to time, we have entered 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

 

  Our production and/or sales of natural gas are less than expected

 

  Payments owed under derivative hedging contracts typically come due prior to receipt of the hedged month’s 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.

 

Competition

 

The Company competes with numerous other companies in virtually all facets of its business. Our competitors in the exploration, development, acquisition and production business include major integrated oil and gas companies as well as numerous independents, including many that have significantly greater financial resources and in-house technical expertise.

 

Government Regulations

 

Federal Income Tax. Federal income tax laws significantly affect the Company’s operations. The principal provisions affecting the Company are those that permit the Company, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, its domestic “intangible drilling and development costs” and to claim depletion on a portion of its domestic natural gas and oil properties based on 15% of its natural gas and oil gross income from such properties (up to an aggregate of 1,000 Bbls per day of domestic crude oil and/or equivalent units of domestic natural gas).

 

Environmental Matters. Domestic natural gas and oil operations are subject to extensive federal regulation and, with respect to federal leases, to interruption or termination by governmental authorities on account of environmental and other considerations such as the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) also known as the “Super Fund Law”. The trend towards stricter standards in environmental legislation and regulation could increase costs to the Company and others in the industry. Natural gas and oil lessees are subject to liability for the costs of clean-up of pollution resulting from a lessee’s operations, and may also be subject to liability for pollution damages. The Company maintains insurance against costs of clean-up operations, but is not fully insured against all such risks. A serious incident of pollution may also result in the Department of the Interior requiring lessees under federal leases to suspend or cease operation in the affected area.

 

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The Oil Pollution Act of 1990 (the OPA) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. The OPA assigns 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 federal safety, construction or operating regulations. Few defenses exist to the liability imposed by the OPA. In addition, to the extent the Company’s offshore lease operations affect state waters, the Company may be subject to additional state and local clean-up requirements or incur liability under state and local laws. The OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities. However, the Company cannot predict whether these financial responsibility requirements under the OPA amendments will result in the imposition of substantial additional annual costs to the Company in the future or otherwise materially adversely affect the Company. The impact, however, should not be any more adverse to the Company than it will be to other similarly situated or less capitalized owners or operators in the Gulf of Mexico.

 

The Company’s onshore operations are subject to numerous federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. Such laws and regulations, among other things, impose absolute liability on the lessee for the cost of clean-up of pollution resulting from a lessee’s operations, subject the lessee to liability for pollution damages, may require suspension or cessation of operations in affected areas, and impose restrictions on the injection of liquids into subsurface aquifers that may contaminate groundwater. Such laws could have a significant impact on the operating costs of the Company, as well as the natural gas and oil industry in general. Federal, state and local initiatives to further regulate the disposal of natural gas and oil wastes are also pending in certain jurisdictions, and these initiatives could have a similar impact on the Company. The Company’s operations are also subject to additional federal, state and local laws and regulations relating to protection of human health, natural resources, and the environment pursuant to which the Company may incur compliance costs or other liabilities.

 

The Company believes that, in the course of conducting its natural gas and oil operations, the costs attributable to environmental control facilities were not considered material to the Company’s overall operations. For the fiscal year ending June 30, 2005, the Company does not anticipate any material capital expenditures for environmental control facilities.

 

Other Laws and Regulations. Various laws and regulations often require permits for drilling wells and also cover spacing of wells, the prevention of waste of natural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions in which the Company has production, could be to limit the number of wells that could be drilled on the Company’s properties and to limit the allowable production from the successful wells completed on the Company’s properties, thereby limiting the Company’s revenues.

 

The MMS administers the natural gas and oil leases held by the Company on federal onshore lands and offshore tracts in the Outer Continental Shelf. The MMS holds a royalty interest in these federal leases on behalf of the federal government. While the royalty interest percentage is fixed at the time that the lease is entered into, from time to time the MMS changes or reinterprets the applicable regulations governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the Company is required to pay. However, the Company believes that the regulations generally do not impact the Company to any greater extent than other similarly situated producers.

 

The FERC has embarked on wide-ranging regulatory initiatives relating to natural gas transportation rates and services, including the availability of market-based and other alternative rate mechanisms to pipelines for transmission and storage services. In addition, the FERC has announced and implemented a policy

 

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allowing pipelines and transportation customers to negotiate rates above the otherwise applicable maximum lawful cost-based rates on the condition that the pipelines alternatively offer so-called recourse rates equal to the maximum lawful cost-based rates. With respect to gathering services, the FERC has issued orders declaring that certain facilities owned by interstate pipelines primarily perform a gathering function, and may be transferred to affiliated and non-affiliated entities that are not subject to the FERC’s rate jurisdiction. The Company cannot predict the ultimate outcome of these developments, or the effect of these developments on transportation rates. Inasmuch as the rates for these pipeline services can affect the natural gas prices received by the Company for the sale of its production, the FERC’s actions may have an impact on the Company. However, the impact should not be substantially different on the Company than it will on other similarly situated natural gas producers and sellers.

 

Government Regulation of LNG Operations. Our LNG operations are subject to extensive regulation under federal, state and local statutes, rules, regulations and other laws. Among other matters, these laws require the acquisition of certain permits and other authorizations before commencement of construction and operation of an LNG receiving terminal. Failure to comply with such rules, regulations and laws could result in substantial penalties.

 

In order to site, construct and operate the Freeport LNG receiving terminal, authorization from FERC under Section 3 of the Natural Gas Act of 1938 was required. The FERC permitting process includes detailed engineering and design work, preparation of an Environmental Impact Statement under the National Environmental Policy Act, and public notices and opportunities for public hearings. Freeport LNG received this authorization in June 2004 to site, construct and operate our proposed LNG receiving terminal. While the Freeport LNG receiving terminal could be in operation as early as June 2007, in September 2004, FERC extended the completion date for the receiving terminal until June 2009.

 

The Freeport LNG receiving terminal will also be subject to Department of Transportation and Coast Guard regulations relating to:

 

  Siting requirements

 

  Design standards

 

  Construction standards

 

  Equipment, operations and maintenance

 

  Personnel qualifications and training

 

  Fire protection

 

  Security

 

In addition, Freeport LNG’s operations are subject to various federal, state and local laws and regulations relating to the protection of the environment, including CERLA. In some cases, these laws and regulations may require Freeport LNG to obtain governmental authorizations before Freeport LNG can conduct certain activities or may require Freeport LNG to limit certain activities in order to protect endangered or threatened species or sensitive areas. These environmental laws may impose substantial penalties for noncompliance and substantial liabilities for pollution and generally increase Freeport LNG’s overall cost of business. Further, environmental regulations have historically been subject to frequent change. Consequently, we are unable to predict the future costs or other future impacts of environmental regulations on our future operations.

 

Employees

 

We 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, land, 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. As working interest owner, we rely on outside operators to drill, produce and market our natural gas and oil. In addition, we utilize the services of independent contractors to perform field and on-site drilling and production operation services.

 

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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

  59   Chairman, President, Chief Executive Officer, Chief Financial Officer, Secretary and Director

William H. Gibbons

  61   Vice President and Treasurer

Lesia Bautina

  33   Vice President and Controller

Jay D. Brehmer

  39   Director

Joseph S. Compofelice

  55   Director

Darrell W. Williams

  61   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 natural gas and oil 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. Mr. Peak’s tenure included serving as President of TIPCO, the domestic operating subsidiary of Texas International Company’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., a provider of onshore contract drilling services to exploration and production companies in North America.

 

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 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 has been a director of Contango since October 2000. Mr. Brehmer is Managing Director of Catalina Capital Advisors LP, a boutique financial advisory, merger and acquisition investment bank. From November 2002 until August 2004, he advised various energy and energy-related companies on corporate finance and merger and acquisition activities through Southplace, LLC. From May 1998 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, which 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

 

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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.

 

Joseph S. Compofelice. Mr. Compofelice has been a director of Contango since 2002. Mr. Compofelice is Managing Director of Catalina Capital Advisors LP, a boutique financial advisory, merger and acquisition investment bank. He is the Chairman of the Board of Trico Marine Services, Inc., a provider of marine support vessels serving the international natural gas and oil industry, and a member of the Board of Advisors of Courtland Inc., a privately held investment management firm. From 2001 to 2003, Mr. Compofelice was 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 through 2002, 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.

 

Darrell W. Williams. Mr. Williams has been a director of Contango since 1999. He 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, the subsidiary 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 life member of the Society of Petroleum Engineers and a registered professional engineer in Texas. He also serves as a business advisor of privately held Porta-Kamp, a company engaged in the design and manufacturing of prefabricated housing and camps.

 

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. During the fiscal year ended June 30, 2004, each outside director received a quarterly retainer of $3,000 and a quarterly stock option grant to purchase 3,000 shares of common stock. Effective July 1, 2004, the quarterly retainer for each outside director was increased to $5,000. Each outside director also 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. Effective June 1, 2004, we increased our office space from 2,850 square feet to 5,377 square feet. Our agreement provides for a monthly rental of $9,970 per month through October 2006.

 

Code of Ethics

 

We adopted a Code of Ethics for senior management in December 2002. A copy of our Code of Ethics is filed as an exhibit to this Form 10-K and is also available on our Website at www.contango.com.

 

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Risk Factors

 

In addition to the other information set forth elsewhere in this Form 10-K, 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:

 

  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 competitive fuels such as heating oil and coal

 

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

 

  The level of LNG imports

 

  Domestic and foreign governmental regulations

 

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 may require additional financing to fund our planned growth. Our ability to raise additional capital will depend on the results of our operations and the status of various capital and industry markets at the time we seek such capital. Accordingly, we cannot be certain that additional financing will be available to us on acceptable terms, if at all. In particular, our credit facility imposes limits on our ability to borrow under the facility based on adjustments to the value of our hydrocarbon reserves, and our credit facility 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.

 

The construction of our LNG receiving terminal in Freeport, Texas is subject to various development risks. We own a 10% limited partnership interest in a proposed LNG receiving facility to be built in Freeport, Texas. The LNG project received FERC approval in June 2004. The LNG receiving facility, however, remains in development stage and subject to development risk such as permitting, cost overruns and delays. Key factors that may affect the completion of the LNG receiving terminal include, but are not limited to: timely issuance of necessary permits, licenses and approvals by governmental agencies and third parties; sufficient financing; unanticipated changes in market demand or supply; competition with similar projects; labor disputes; site difficulties; environmental conditions; unforeseen events, such as hurricanes, explosions, fires and product spills; delays in manufacturing and delivery schedules of critical equipment and materials; resistance in the local community; local and general economic conditions; and commercial arrangements for pipelines and related equipment to transport and market LNG.

 

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

 

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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. In December 2003, ConocoPhillips and Freeport LNG signed an agreement providing for ConocoPhillips’ participation in Freeport LNG’s project to build the receiving terminal. ConocoPhillips will acquire one billion cubic feet per day of capacity in the terminal for its use, obtain a 50% interest in the general partner of Freeport LNG, and provide construction funding presently estimated in excess of $500 million. Without such financing or any significant shortfall in project funding, 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.

 

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

 

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

 

Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves shown in this report. In addition, estimates of our proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control. Some of the producing wells included in our reserve report have produced for a relatively short period of time as of June 30, 2004. Because some of our reserve estimates are not based on a lengthy production history and are calculated using volumetric analysis, these estimates are less reliable than estimates based on a more lengthy production history.

 

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

 

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

 

We are highly dependent on the technical services provided by our alliance partners and could be seriously harmed if our alliance agreements were terminated. Because we have only four employees, none of whom are geoscientists or petroleum engineers, we are dependent upon alliance partners for the success of our natural gas and oil exploration projects and expect to remain so for the foreseeable future. Highly qualified explorationists and engineers are difficult to attract and retain in this industry. As a result, the loss of the services of one or more of our alliance partners could have a material adverse effect on us and could prevent us from pursuing our business plan. Additionally, the loss by our alliance partners of certain explorationists 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 rely on 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:

 

  Unexpected drilling conditions

 

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

 

  Pressure or irregularities in formations

 

  Equipment failures or accidents

 

  Adverse weather conditions

 

  Compliance with governmental requirements and laws, present and future

 

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

 

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

 

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

 

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

 

  Blowouts, fires and explosions

 

  Surface cratering

 

  Uncontrollable flows of underground natural gas, oil or formation water

 

  Natural disasters

 

  Pipe and cement failures

 

  Casing collapses

 

  Stuck drilling and service tools

 

  Abnormal pressure formations

 

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

 

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

 

  Injury or loss of life

 

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

 

  Pollution and other environmental damage

 

  Clean-up responsibilities

 

  Regulatory investigation and penalties

 

  Suspension of our operations or 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.

 

We may face operational and financial risks associated with foreign exploration and development. We recently unsuccessfully drilled a well in the Aquitaine Basin in southwestern France. We have no future drilling plans in France If, however, we pursue further activities in France or elsewhere outside of the United States, we will face operational and financial risks associated with foreign exploration and development.

 

Not hedging our production may result in losses. Due to the significant volatility in natural gas prices and the potential risk of significant hedging losses if NYMEX natural gas prices spike on the date options settle, our policy is to hedge only through the purchase of puts. By not hedging our production, we may be more adversely affected by declines in natural gas and oil prices than our competitors who engage in hedging arrangements.

 

Our ability to market our natural gas and oil may be impaired by capacity constraints 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

 

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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.

 

Our natural gas and oil production is concentrated in south Texas and is sold to a limited number of purchasers. Substantially all of our current production comes from wells drilled in south Texas. This production is gathered on a single pipeline and is sold on a spot market basis to one purchaser. Any disruption of our pipeline or marketing arrangements or financial difficulties with any purchaser, or alternative marketing sources, could have an adverse effect on our ability to market our natural gas and oil production. Additionally, if a 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 our alliance partners to perform the field work in examining records in the appropriate governmental, county or parish clerk’s office before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to the drilling of an exploration well the operator of the well will typically obtain a preliminary title review of the drillsite lease and/or spacing unit within which the proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible. We have no assurance, however, that any such deficiencies have been cured by the operator of any such wells. It does happen, from time to time, that the examination made by 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 evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and oil and to acquire additional properties in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of our competitors have been operating for a much longer time than we have and have substantially larger staffs. We may not be able to compete effectively with these companies or in such a highly competitive environment.

 

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

 

  Require that we obtain permits before commencing drilling

 

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

 

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

 

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

 

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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 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

 

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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

 

Our common stock is thinly traded. Contango has approximately 13 million shares of common stock outstanding, approximately 5.5 million shares of which are owned by directors, officers and affiliates. We have fewer than 3,000 stockholders, and our daily trading volume is frequently less than 10,000 shares. The purchase or sale of relatively small common stock positions may result in disproportionately large increases or decreases in the price of our common stock.

 

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Item 2. Description of Properties

 

Production, Prices and Operating Expenses

 

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,

     2004

   2003

   2002

Production:

                    

Natural gas (thousand cubic feet)

     4,328,507      6,016,395      6,981,909

Oil and condensate (barrels)

     99,492      138,569      186,274

Total (thousand cubic feet equivalent)

     4,925,459      6,847,809      8,099,553

Natural gas (thousand cubic feet per day)

     11,827      16,483      19,129

Oil and condensate (barrels per day)

     272      380      510

Total (thousand cubic feet equivalent per day)

     13,459      18,763      22,189

Average sales price:

                    

Natural gas (per thousand cubic feet)

   $ 5.65    $ 5.00    $ 2.94

Oil and condensate (per barrel)

   $ 31.99    $ 27.90    $ 21.44

Total (per thousand cubic feet equivalent)

   $ 5.61    $ 4.95    $ 3.03

Selected data per Mcfe:

                    

Production and severance taxes

   $ 0.16    $ 0.35    $ 0.20

Lease operating expense

   $ 0.63    $ 0.48    $ 0.28

General and administrative expense

   $ 0.55    $ 0.30    $ 0.36

Depreciation, depletion and amortization of natural gas and oil properties

   $ 1.39    $ 1.24    $ 1.05

 

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,

     2004

   2003

   2002

Property Acquisition Costs:

                    

Unproved

   $ 4,475,908    $ 972,658    $ 1,063,204

Proved

     —        2,602,551      23,449,488

Exploration costs

     6,923,762      19,194,281      7,138,690

Developmental costs

     983,933      —        —  
    

  

  

Total costs

   $ 12,383,603    $ 22,769,490    $ 31,651,382
    

  

  

 

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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,

     2004

   2003

   2002

     Gross

   Net

   Gross

   Net

   Gross

   Net

Exploratory Wells:

                             

Productive

   8    3.9    11    5.2    9    6.5

Non-productive

   6    1.6    4    1.9    3    1.4
    
  
  
  
  
  

Total

   14    5.5    15    7.1    12    7.9
    
  
  
  
  
  

Development Wells:

                             

Productive

   1    0.8    —      —      —      —  

Non-productive

   —      —      —      —      —      —  
    
  
  
  
  
  

Total

   1    0.8    —      —      —      —  
    
  
  
  
  
  

 

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, 2004:

 

     Developed
Acreage (1)(2)


   Undeveloped
Acreage (1)(3)


     Gross (4)

   Net (5)

   Gross (4)

   Net (5)

Onshore Texas

   11,702    7,200    5,613    2,297

Offshore Gulf of Mexico

   3,333    333    93,207    83,704
    
  
  
  

Total

   15,035    7,533    98,820    86,001
    
  
  
  

(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 represent 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).

 

Included in the 93,207 gross and 83,704 net offshore Gulf of Mexico acres shown in the table above are the beneficial interests Contango Oil & Gas Company has in the offshore acreage owned by its partially owned subsidiaries. The above table includes (i) our 33.3% interest in Republic Exploration’s 92,094 gross offshore undeveloped acres (83,520 net undeveloped acres), (ii) our 66.7% interest in Contango Offshore Exploration 5,000 gross offshore developed acres (500 net undeveloped acres) and in 78,194 gross offshore undeveloped acres (73,194 net undeveloped acres), and (iii) our 50% interest in Magnolia Offshore Exploration’s 10,760 gross offshore undeveloped acres (10,760 net undeveloped acres).

 

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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, 2004:

 

     Total Productive
Wells (1)


     Gross (2)

   Net (3)

Natural gas

   46    27.7

Oil

   —      —  
    
  

Total

   46    27.7
    
  

(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, 2004, based on a reserve report generated by W.D. Von Gonten & Co. The pre-tax net present value is not intended to represent the current market value of the estimated natural gas and oil reserves we own.

 

The pre-tax net present value of future cash flows attributable to our proved reserves prepared in accordance with SEC guidelines as of June 30, 2004 was based on $5.90 per MMbtu for natural gas at the Houston Ship Channel (which equated to a NYMEX price of $6.16 per MMbtu) and to a NYMEX oil price of $37.05 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, 2004

     Producing

   Behind Pipe

   Undeveloped

   Total

Natural gas (MMcf)

     15,543      91      —        15,634

Oil and condensate (MBbls)

     295      2      —        297

Total proved reserves (MMcfe)

     17,313      103      —        17,416

Pre-tax net present value ($000)

   $ 59,537    $ 230    $ —      $ 59,767

 

The process of estimating natural gas and oil reserves is complex. It requires various assumptions, including natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Our third party engineers must project production rates, estimate timing and amount of development expenditures, analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of all 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, estimates of proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control.

 

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.

 

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Item 3. Legal Proceedings

 

As of the date of this Form 10-K, 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, 2004, no matters were submitted to a vote of security holders.

 

PART II

 

Item 5. Market for Registrant’s 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 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

Fiscal Year 2004:

             

Quarter ended September 30, 2003

   $ 4.59    $ 3.88

Quarter ended December 31, 2003

   $ 7.03    $ 4.03

Quarter ended March 31, 2004

   $ 8.48    $ 6.42

Quarter ended June 30, 2004

   $ 7.82    $ 5.45

 

On September 15, 2004, the closing price of our common stock on the American Stock Exchange was $6.40 per share, and there were 12,977,366 shares of Contango common stock outstanding, held by 137 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 C, our plan is to retain any future earnings for use in the operations and expansion of our natural gas and oil exploration business and as needed in our LNG and alternative energy activities. 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 December 12, 2003, we sold $8.0 million of our Series C preferred stock to a group of private institutional investors. The sale of the Series C preferred stock was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D promulgated thereunder, as a transaction not involving a public offering. The Series C preferred stock is perpetual, is senior to our common stock and is convertible at any time into shares of our common stock at a price of $6.00 per share. The dividend on the Series C preferred stock can be paid quarterly in cash at a rate of 6.0% per annum or paid-in-kind at a rate of 7.5% per annum. We used the net proceeds of this offering to repay indebtedness under our bank revolving credit facility. We intend to use the additional funds made available under our bank credit facility, together with cash flow from operations, to fund natural gas and oil exploration, development and production, to fund offshore lease acquisitions, to fund 3-D seismic shoots and acquisitions, to fund our investment in our proposed Freeport, Texas LNG receiving terminal and for general corporate purposes. We have filed a shelf registration

 

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with the Securities and Exchange Commission, which has become effective, covering the 1,333,328 shares of common stock issuable upon conversion of the Series C preferred stock, an additional 1,217,685 shares of common stock that are issuable upon the exercise of certain stock options and warrants and 200,000 shares of common stock that may be issuable as a result of payment of the Series C preferred stock dividends in kind.

 

During the fiscal year ended June 30, 2004, no shares of common stock were issued to employees or consultants.

 

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Item 6. Selected Financial Data

 

     Year Ended June 30,

 
     2004

   2003

    2002

   2001

    2000 (1)

 
     (Dollar amounts in 000s, except per share amounts)  

Financial Data:

                                      

Revenues:

                                      

Natural gas and oil sales

   $ 27,630    $ 33,919     $ 23,902    $ 24,549     $ 298  

Gain (loss) from hedging activities

     58      (5,709 )     5,016      (558 )     —    
    

  


 

  


 


Total revenues

   $ 27,688    $ 28,210     $ 28,918    $ 23,991     $ 298  

Net income (loss)

   $ 7,700    $ (4,336 )   $ 6,577    $ 7,737     $ (1,847 )

Preferred stock dividends

     620      600       600      475       —    
    

  


 

  


 


Net income (loss) attributable to common stock

   $ 7,080    $ (4,936 )   $ 5,977    $ 7,262     $ (1,847 )
    

  


 

  


 


Net income (loss) per share:

                                      

Basic

   $ 0.68    $ (0.54 )   $ 0.55    $ 0.64     $ (0.37 )

Diluted

   $ 0.58    $ (0.54 )   $ 0.48    $ 0.54     $ (0.37 )

Weighted average shares outstanding:

                                      

Basic

     10,484      9,129       10,842      11,287       4,954  

Diluted

     13,280      9,129       13,712      14,381       4,954  

EBITDAX (2)

   $ 28,986    $ 20,901     $ 22,486    $ 19,002     $ (481 )

Working capital (deficit)

   $ 3,356    $ (1,676 )   $ 3,928    $ 4,782     $ 4,930  

Capital expenditures

   $ 12,384    $ 22,769     $ 31,651    $ 22,769     $ 2,957  

Long term debt

   $ 7,089    $ 16,460     $ 17,620    $ —       $ —    

Stockholders’ equity

   $ 36,117    $ 20,738     $ 25,098    $ 25,020     $ 6,405  

Total assets

   $ 45,511    $ 46,305     $ 51,840    $ 31,722     $ 6,643  

 

     Year Ended June 30,

     2004

   2003

   2002

   2001

   2000

Production Data:

                                  

Natural gas (million cubic feet)

     4,329      6,016      6,982      3,570      28

Oil and condensate (thousand barrels)

     99      139      186      122      6

Total (million cubic feet equivalent)

     4,923      6,850      8,098      4,302      64

Natural gas (thousand cubic feet per day)

     11,827      16,483      19,129      9,781      77

Oil and condensate (barrels per day)

     272      380      510      335      17

Total (thousand cubic feet equivalent per day)

     13,459      18,763      22,189      11,791      179

Average sales price:

                                  

Natural gas (per thousand cubic feet)

   $ 5.65    $ 5.00    $ 2.94    $ 5.92    $ 4.16

Oil and condensate (per barrel)

   $ 31.99    $ 27.90    $ 21.44    $ 27.95    $ 28.43

Selected data per Mcfe:

                                  

Production and severance taxes

   $ 0.16    $ 0.35    $ 0.20    $ 0.39    $ 0.12

Lease operating expenses

   $ 0.63    $ 0.48    $ 0.28    $ 0.22    $ 1.16

General and administrative expenses

   $ 0.55    $ 0.30    $ 0.36    $ 0.55    $ 11.50

Depreciation, depletion and amortization of natural gas and oil properties

   $ 1.39    $ 1.24    $ 1.05    $ 0.92    $ 5.15

Proved Reserve Data:

                                  

Total proved reserves (Mmcfe)

     17,422      23,592      27,939      18,144      4

Pre-tax net present value (SEC at 10%)

   $ 59,767    $ 69,627    $ 53,349    $ 42,626    $ 12,260

(1) We commenced natural gas and oil operations in July 1999.
(2) EBITDAX represents earnings before interest, income taxes, depreciation, depletion and amortization, impairment expenses, exploration expenses, including gain (loss) from hedging activities, and sale of assets and other. 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

 

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

 

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

 

     Year ended June 30,

 
     2004

   2003

    2002

   2001

   2000

 
     ($000)  

Income (loss) from operations

   $ 4,199    $ (6,481 )   $ 10,297    $ 10,511    $ (2,048 )

Exploration expenses

     9,873      17,922       2,694      4,167      604  

Depreciation, depletion and amortization

     6,989      8,788       8,594      4,024      345  

Impairment of natural gas and oil properties

     43      181       527      300      548  

Gain on sale of marketable securities

     710      452       —        —        —    

Gain on sale of assets and other

     7,172      39       374      —        70  
    

  


 

  

  


EBITDAX

   $ 28,986    $ 20,901     $ 22,486    $ 19,002    $ (481 )
    

  


 

  

  


 

Item 7. 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.

 

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, both onshore Gulf Coast and offshore in the Gulf of Mexico. Our primary source of natural gas and oil production currently is in south Texas. We also own a 10% partnership interest in Freeport LNG Development, L.P., which is developing a 1.5 Bcf per day LNG receiving terminal in Freeport, Texas and have a 32% interest in Contango Capital Partnership Management, LLC, which was formed to invest in the alternative energy venture capital market.

 

Revenues and Profitability. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil and on our ability to find, develop and acquire natural gas and oil reserves that are economically recoverable and the completion and successful operation of our Freeport LNG Project. The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved natural gas and oil reserves. We use the successful efforts method of accounting for our natural gas and oil activities.

 

Reserve Replacement. Generally, our producing properties onshore Gulf Coast and offshore in the Gulf of Mexico have high initial production rates, followed by steep declines. As a result, we must locate and develop or acquire new natural gas and oil reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire natural gas and oil reserves.

 

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Use of Estimates. The preparation of our financial statements requires the use of 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 estimates of remaining proved natural gas and oil reserves and the timing and costs of our future drilling, development and abandonment activities.

 

Please see “Risk Factors” on page 13 for a more detailed discussion of a number of other factors that affect our business, financial condition and results of operations.

 

Results of Operations

 

The following is a discussion of the results of our operations for the fiscal year ended June 30, 2004, compared to the fiscal year ended June 30, 2003 and for the fiscal year ended June 30, 2003, compared to the fiscal year ended June 30, 2002.

 

Revenues. All of our revenues are from the sale of our natural gas and oil production and the settlement of hedging contracts associated with our natural gas and oil production. Our revenues may vary significantly from year to year depending on changes in commodity prices and production volumes.

 

The table below sets forth revenue and production data for the fiscal years ended June 30, 2004, 2003 and 2002:

 

     Year ended June 30,

          Year ended June 30,

      
     2004

   2003

    %

    2003

    2002

   %

 
     ($000)           ($000)       

Revenues:

                                          

Natural gas and oil sales

   $ 27,630    $ 33,919     -19 %   $ 33,919     $ 23,902    42 %

Gain (loss) from hedging activities

     58      (5,709 )   *       (5,709 )     5,016    *  
    

  


       


 

      

Total revenues

   $ 27,688    $ 28,210           $ 28,210     $ 28,918       

Production:

                                          

Natural gas (million cubic feet)

     4,329      6,016     -28 %     6,016       6,982    -14 %

Oil and condensate (thousand barrels)

     99      139     -29 %     139       186    -25 %

Total (million cubic feet equivalent)

     4,923      6,850     -28 %     6,850       8,098    -15 %

Natural gas (million cubic feet per day)

     11.8      16.5     -28 %     16.5       19.1    -14 %

Oil and condensate (barrels per day)

     272      380     -28 %     380       510    -25 %

Total (million cubic feet per day equivalent)

     13.5      18.8     -28 %     18.8       22.2    -15 %

Average Sales Price:

                                          

Natural gas (per thousand cubic feet)

   $ 5.65    $ 5.00     13 %   $ 5.00     $ 2.94    70 %

Oil and condensate (per barrel)

   $ 31.99    $ 27.90     15 %   $ 27.90     $ 21.44    30 %

* Not meaningful

 

Natural Gas and Oil Sales. Substantially all of our natural gas and oil sales are from our production in south Texas. We reported natural gas and oil sales of approximately $27.6 million for the year ended June 30, 2004, down from approximately $33.9 million reported for the year ended June 30, 2003. This decrease was principally attributable to normal production declines in our existing south Texas properties and the sale of non-core producing properties in Brooks County, Texas. These declines were partially offset by increases in average prices received for our natural gas and oil production.

 

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.

 

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Natural Gas and Oil Production and Average Sales Prices. For the year ended June 30, 2004, our net natural gas production was approximately 11.8 million cubic feet of natural gas per day, down from approximately 16.5 million cubic feet of natural gas per day for the year ended June 30, 2003. Net oil production for the period was down from 380 barrels of oil per day to 272 barrels of oil per day. These decreases primarily were due to normal production declines in our existing south Texas properties and the sale of non-core producing properties in Brooks County, Texas. For the year ended June 30, 2004, prices for natural gas and oil were $5.65 per Mcf and $31.99 per barrel, up from $5.00 per Mcf and $27.90 per barrel for the year ended June 30, 2003.

 

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 south Texas 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 gain from hedging activities for the year ended June 30, 2004 of approximately $58,200. For the year ended June 30, 2003, we reported a loss from hedging activities 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.

 

Operating Expenses. Operating expenses, including severance taxes, for the year ended June 30, 2004 were approximately $3.9 million, down from the $5.7 million reported for the year ended June 30, 2003. Of the $3.9 million reported for the year ended June 30, 2004, approximately $3.1 million was attributable to lease operating expense and approximately $0.8 million was attributable to production and severance taxes. The decrease in operating expenses for the year ended June 30, 2004 was attributable to lower production and the extension of a natural gas incentive by the Railroad Commission of Texas to allow for severance tax reduction on tight sand gas wells. As a result, some of our south Texas Queen City formation properties are eligible for severance tax reduction.

 

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 $2.4 million was attributable to production and severance taxes and approximately $3.3 million was attributable to lease operating expense. 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 south Texas properties and to higher overall costs of operations. These cost increases were partially offset by lower production.

 

Operating expenses for the year ended June 30, 2002 totaled approximately $3.9 million and included approximately $2.2 million of lease operating expenses and $1.7 million of production and severance taxes.

 

Exploration Expense. We reported approximately $9.9 million of exploration expenses for the year ended June 30, 2004. Of this amount, approximately $3.6 million was attributable to dry holes drilled in south Texas ($2.8 million) and to our unsuccessful well drilled in France ($0.8 million), approximately $2.7 million was attributable to seismic costs and delay rentals associated with activities onshore in south Texas and approximately $3.6 million was attributable to seismic costs and delay rentals associated with activities offshore in the Gulf of Mexico.

 

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.

 

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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 south Texas properties and $0.5 million 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 fiscal years ended June 30, 2004, 2003 and 2002 were approximately $7.0 million, $8.8 million and $8.6 million, respectively. Depreciation, depletion and amortization for these periods was attributable primarily to depletion and amortization related to production onshore in south Texas. The decrease in 2004 was primarily due to lower levels of production and a lower unit DD&A rate. The increase in 2003 was due to the cost of new wells drilled.

 

Impairment of Natural Gas and Oil Properties. Impairment expense for the year ended June 30, 2004 and 2003 was approximately $43,000 and $181,600, respectively. These 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 increased from approximately $2.1 million for the year ended June 30, 2003 to approximately $2.7 million for the year ended June 30, 2004. Major components of general and administrative expenses for the year ended June 30, 2004 included approximately $744,000 in salaries and benefits, $488,000 in legal, accounting, engineering and other professional fees, $344,000 of office administration and $248,000 of insurance costs. Also included in total general and administrative expenses for the year ended June 30, 2004 was approximately $339,000 related to the cost of expensing stock options, $215,000 related to our Gulf of Mexico exploration activities, $74,000 for Board compensation expense and $244,000 in other 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 $497,000 in salaries and benefits, $723,000 in legal, accounting, engineering and other professional fees (including $235,000 of one time costs associated with the proposed sale of our south Texas properties and property ownership restructuring), $267,000 of office administration and $130,000 of insurance costs. Also included in total general and administrative expenses for the year ended June 30, 2003 was approximately $134,000 related to the cost of expensing stock options, $167,000 related to our Gulf of Mexico exploration activities, $66,000 for Board compensation expense and $78,000 in other expenses.

 

General and administrative expenses for the year ended June 30, 2002 were approximately $2.9 million. Major components of general and administrative expenses for the year ended June 30, 2002 included approximately $963,000 in salaries and benefits, $1,047,000 in legal, accounting, engineering and other professional fees (including $543,000 of one time costs associated with the proposed public offering of our Series C preferred stock), $207,000 of office administration and $126,000 of insurance costs. Also included in total general and administrative expenses for the year ended June 30, 2002 was approximately $30,000 related to the cost of expensing stock options, $302,000 related to our Gulf of Mexico exploration activities and $227,000 in other expenses.

 

The increase in general and administrative expenses between the fiscal years 2004 and 2003 was primarily due to increases in salaries and benefits resulting primarily from employee bonus payments made during fiscal year 2004, higher insurance cost, principally directors’ and officers’ insurance, and higher stock option expenses. These increases were offset by lower legal and other professional fees. The decrease in general and administrative expenses between the fiscal years 2003 and 2002 was primarily due to decreases in salaries and benefits (resulting primarily from a lower level of employee bonus payments) and decreases in legal expenses.

 

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Interest Expense. Interest expense for the fiscal years ended June 30, 2004, 2003 and 2002 were approximately $0.4 million, $0.7 million and $0.3 million, respectively. The higher level of interest for the fiscal year 2003 was attributable to higher level of bank debt during the period primarily to fund seismic and other geological and geophysical costs and to acquire properties in south Texas. The lower level of interest in fiscal year 2004 was attributable to lower levels of bank debt during the period. Interest rates were relatively constant during the three year period.

 

Gain on Sale of Marketable Equity Securities. As part of the formation of Freeport LNG Development, L.P., Cheniere granted Contango warrants to purchase 300,000 shares of Cheniere common stock. In June and September 2003, Contango exercised the warrants, purchasing 300,000 shares of Cheniere common stock. As of June 30, 2004, the Company had sold 300,000 shares of Cheniere common stock and reported a gain on the sale of marketable securities for the year ended June 30, 2004 of $710,322.

 

Gain on Sale of Assets and Other. For the year ended June 30, 2004, we reported an approximate $7.2 million gain on the sale of assets. In September 2003, we sold properties within our south Texas exploration program consisting of 10 wells in Brooks County, Texas for $5.0 million, reporting a gain of approximately $1.0 million attributable to this producing property sale.

 

In December 2003, Contango and its 33.3%-owned subsidiary, Republic Exploration, sold their producing Gulf of Mexico leases for approximately $12.0 million. As a result of this sale, Contango recorded a gain of approximately $6.2 million as of June 30, 2004. Properties included in the sale were Eugene Island 110, Grand Isle 28 and High Island 25-L. Because the interests sold were unearned back-in working interests, Contango had no proved reserves attributable to the properties sold (see footnote 7 to Notes to Consolidated Financial Statements).

 

For the year ended June 30, 2002, we reported a gain of approximately $0.4 million. This was attributable to gains on leases sold by Republic Exploration and 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, 2004, we funded our activities with internally generated cash flow, bank borrowings, sales of assets and the sale of our Series C preferred stock. We currently expect to spend $10.0 to $20.0 million on natural gas and oil exploration activities during fiscal year 2005. The majority of our spending will be for exploration activities. We reported total revenues and EBITDAX for the year ended June 30, 2004 of approximately $27.7 million and $29.0 million, respectively. Our current production rate is approximately 15.0 MMBtue per day. At anticipated production levels and current commodity price levels, we expect to have EBITDAX of $1.5 to $2.0 million per month through December 2004.

 

We believe that our cash on hand, our anticipated cash flow from operations and funds available under our credit facility will be adequate over the next twelve months to satisfy planned capital expenditures to fund drilling activities, our share of construction costs related to the Freeport LNG receiving terminal and incremental investments in Contango Venture Capital Corporation and to satisfy general corporate needs. We may seek additional equity, sell assets or seek other financing to fund our 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.

 

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Contractual Obligations

 

Presented below are our contractual commitments for the periods indicated. See “Credit Facility” below for a description of our secured, reducing revolving bank line of credit.

 

          Fiscal Year Ending June 30,

     Total

   2005

   2006

   2007

   2008

   Thereafter

Office lease

   $ 274,471    $ 114,953    $ 119,638    $ 39,880    $  —      $  —  

Office equipment

     8,590      7,363      1,227      —        —        —  
    

  

  

  

  

  

Total

   $ 283,061    $ 122,316    $ 120,865    $ 39,880    $  —      $  —  
    

  

  

  

  

  

 

Credit Facility

 

Our credit facility is a secured, reducing revolving line of credit with Guaranty Bank, FSB, secured by our natural gas and oil reserves. In September 2004, the borrowing base was redetermined to $21.0 million in two tranches. Tranche A provides for a borrowing base of $19.0 million and matures on June 29, 2006. This amount reduces by $595,000 per month the first day of each month beginning November 1, 2004. Borrowings under Tranche A bear interest, at our option, at either (i) LIBOR plus two percent (2%) or (ii) the bank’s base rate plus one-fourth percent (1/4%) per annum. Additionally, we pay a quarterly commitment fee of three-eighths percent (3/8%) per annum on the average availability of Tranche A. Tranche B provides for a borrowing base of $2.0 million and matures on April 1, 2005. Borrowings under Tranche B will reduce by $595,000 per month the first day of each month following the month in which Tranche B is funded, with the final reduction on April 1, 2005. Further, any amounts borrowed and repaid under Tranche B cannot be reborrowed. Borrowings under Tranche B bear interest, at the Company’s option, at either (i) LIBOR plus three percent (3%) or (ii) the bank’s base rate plus three-quarters percent (3/4%) per annum. Additionally, we pay a quarterly commitment fee of one-half percent (1/2%) per annum on the average availability under Tranche B.

 

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

 

As of June 30, 2004, the Company’s long-term debt totaled $7.1 million, all of which was outstanding under Tranche A of the line of credit. The average interest rate on the Company’s long-term debt at June 30, 2004 was 3.3%. As of June 30, 2004, the Company was in compliance with its financial covenants, ratios and other provisions of the credit facility.

 

On September 15, 2004, we had approximately $0.9 million in cash on hand, $1.0 million borrowed under our credit facility and approximately $20.4 million of unused bank borrowing capacity.

 

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

 

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

 

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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, 2004 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, 2004 and 2003, the Company had cash and cash equivalents of $396,753 and $219,242, respectively. 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 related 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 4 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 differences between the tax basis 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.

 

Fair Value of Financial Instruments. The carrying amounts of the Company’s short-term financial instruments, including cash equivalents, trade accounts receivable and trade accounts payable, approximate their fair values based on the short maturities of those instruments. The Company’s long-term debt is variable rate debt and, as such, approximates fair value, as interest rates are variable based on prevailing market rates.

 

Successful Efforts Method of Accounting. The Company follows the successful efforts method of accounting for its natural gas and oil activities. Under the successful efforts method, lease acquisition costs and

 

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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 basis using the unit of production method, with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves.

 

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

 

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

 

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

 

During the quarter ended December 31, 2002, both Republic Exploration and Magnolia Offshore Exploration completed exploration activities to fully expend the Company’s initial cash contributions to the ventures thereby triggering a change in profit and loss allocations. This triggering event earned the other partners in Republic Exploration and Magnolia Offshore Exploration the right to receive their proportionate share of the Company’s initial investment in Republic Exploration and Magnolia Offshore Exploration. As such, the Company proportionately consolidated 33.3% of Republic Exploration’s and 50.0% of Magnolia Offshore Exploration’s net assets as of December 31, 2002, as opposed to 100% of each ventures’ net assets as of September 30, 2002. The reduction of the Company’s ownership in the net assets of Republic Exploration and Magnolia Offshore Exploration resulted in a non-cash exploration expense of approximately $4.2 million and approximately $200,000, respectively. The Company’s cash contributions to Contango Offshore Exploration during the year ended June 30, 2004 that were expended for geological and geophysical data resulted in an approximate $2.5 million exploration expense. The Company’s proportionate share of the ventures’ cash balances is classified as other long-term assets since it is expected those funds will be expended for their intended purposes.

 

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

 

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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.

 

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

 

Investment in Contango Capital in which Contango has 32% ownership is accounted for using the equity method. Under the equity method, only Contango’s investment in and amounts due to and from the equity investee are included in the consolidated balance sheet.

 

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

 

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

 

  The equity investors (if any) do not have a controlling financial interest

 

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

 

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

 

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

 

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

 

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

 

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

 

The Company has determined that the fair value method is preferable to the intrinsic value method previously applied. During the years ended June 30, 2004, 2003 and 2002, the Company recorded a charge of $339,005, $134,431 and $29,796 to general and administrative expense, respectively. Because compensation expense is recognized over a vesting period, the effect of applying the fair value method in the initial years of implementation may not be representative of the effects on net income (loss) that will be reported in future years.

 

Derivative Instruments and Hedging Activities. Contango previously has 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 are 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.

 

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

 

     Year Ended June 30,

 
     2004

   2003

    2002

 

Mark-to-market reversal of prior period unrealized recognized loss (gain)

   $ 58,171    $ 125,674     $ (888,400 )

Net cash received (paid) from swap settlements/options purchased

     —        (5,776,461 )     6,030,247  

Mark-to-market loss unrealized

     —        (58,171 )     (125,674 )
    

  


 


Gain (loss) from hedging activities

   $ 58,171    $ (5,708,958 )   $ 5,016,173  
    

  


 


 

Although the Company’s hedging transactions generally have been designed as economic hedges for a portion of future natural gas and oil production, the Company elected not to designate the derivative instruments as “hedges” under SFAS 133. As a result, gains and losses, representing changes in these derivative instruments’ mark-to-market fair values, were recognized in the Company’s earnings. The Company had no open commodity derivative contracts at June 30, 2004 and has a policy to hedge only through the purchase of puts.

 

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Asset Retirement Obligation. The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”, (“SFAS 143”), as of July 1, 2002. SFAS requires the Company to record the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. 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. Activities related to the Company’s ARO during the year ended June 30, 2004 and 2003 are as follows:

 

     Year Ended June 30,

     2004

    2003

Initial ARO as of July 1

   $ 191,664     $ 172,638

Liabilities incurred during period

     6,987       9,666

Liabilities settled during period

     (129,336 )     —  

Accretion expense

     15,490       9,360
    


 

Balance of ARO as of June 30

   $ 84,805     $ 191,664
    


 

 

Item 7a. 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, 2004, a 10% fluctuation in the prices received for natural gas and oil production would have had an approximate $2.8 million impact on our revenues.

 

Hedging Activities. 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.

 

Interest Rate Risk. The carrying value of our debt approximates fair value. At June 30, 2004, we had approximately $7.1 million of long-term debt. This debt 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, 2004 was 3.3%. The results of a 10% fluctuation in short-term rates would have had an approximate $10,000 impact on interest expense for the year ended June 30, 2004.

 

Item 8. Financial Statements and Supplementary Data

 

The financial statements and supplemental information required to be filed under Item 8 of Form 10-K are presented on pages Page F-1 through F-25 of this Form 10-K.

 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

None.

 

Item 9a. 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 over financial reporting. 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 and procedures subsequent to the date of that evaluation.

 

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Item 9b. Other Information

 

None.

 

PART III

 

Item 10. Directors and Executive Officers of the Registrant

 

The information regarding directors, executive officers, promoters and control persons required under Item 10 of Form 10-K will be contained in our Definitive Proxy Statement for our 2004 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, 2004.

 

Item 11. Executive Compensation

 

The information required under Item 11 of Form 10-K will be contained in the Proxy Statement under the heading “Executive Compensation” and is incorporated herein by reference.

 

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

The information required under Item 12 of Form 10-K will be contained in the Proxy Statement under the heading “Security Ownership of Certain Other Beneficial Owners and Management” and is incorporated herein by reference.

 

Item 13. Certain Relationships and Related Transactions

 

The information required under Item 13 of Form 10-K 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 14. Principal Accountant Fees ands Services

 

The information required under Item 14 of Form 10-K will be contained in the Proxy Statement under the heading “Principal Accountant Fees ands Services” and is incorporated herein by reference.

 

PART IV

 

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

 

(a) Financial Statements and Schedules:

 

The financial statements are set forth in pages F-1 to F-25 of this Form 10-K. Financial statement schedules have been omitted since they are either not required, not applicable, or the information is otherwise included.

 

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(b) Exhibits:

 

The following is a list of exhibits filed as part of this Form 10-K. 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. (7)
3.2   Bylaws of Contango Oil & Gas Company, a Delaware corporation. (7)
3.3   Agreement of Plan of Merger of Contango Oil & Gas Company, a Delaware corporation, and Contango Oil & Gas Company, a Nevada corporation. (7)
3.4   Amendment to the Certificate of Incorporation of Contango Oil & Gas Company, a Delaware corporation. (15)
4.1   Facsimile of common stock certificate of the Company. (1)
4.2   Certificate of Designations, Preferences and Relative Rights and Limitations for Series C Senior Convertible Cumulative Preferred Stock of Contango Oil & Gas Company, a Delaware corporation. (19)
10.1   Agreement, dated effective as of September 1, 1999, between Contango Oil & Gas Company and Juneau Exploration, L.L.C. (2)
10.2   Securities Purchase Agreement between Contango Oil & Gas Company and Trust Company of the West, dated December 29, 1999. (12)
10.3   Warrant to Purchase Common Stock between Contango Oil & Gas Company and Trust Company of the West, dated December 29, 1999. (3)
10.4   Co-Sale Agreement among Kenneth R. Peak, Contango Oil & Gas Company and Trust Company of the West, dated December 29, 1999. (3)
10.5   Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Trust Company of the West. (4)
10.6   Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Fairfield Industries Incorporated. (4)
10.7   Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Juneau Exploration Company, L.L.C. (4)
10.8   Amendment dated August 14, 2000 to agreement between Contango Oil & Gas Company and Juneau Exploration Company, LLC. dated effective as of September 1, 1999. (5)
10.9   Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (8)
  10.10   First Amendment dated as of January 8, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (9)
  10.11   Asset Purchase Agreement by and among Juneau Exploration, L.P. and Contango Oil & Gas Company dated January 4, 2002. (9)
  10.12   Asset Purchase Agreement by and among Mark A. Stephens, John Miller, The Hunter Revocable Trust, Linda G. Ferszt, Scott Archer and the Archer Revocable Trust and Contango Oil & Gas Company dated January 9, 2002. (10)
  10.13   Second Amendment dated as of February 13, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (11)
  10.14   Waiver dated as of March 25, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (11)
  10.15   Option Purchase Agreement between Contango Oil & Gas Company and Cheniere Energy, Inc. dated June 4, 2002. (13)
  10.16   Waiver and Third Amendment dated as of April 26, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (14)
  10.17   Fourth Amendment dated as of September 9, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (14)
  10.18   Fifth Amendment, effective June 1, 2003, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (16)
  10.19   Sixth Amendment, effective September 1, 2003, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (18)

 

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10.20   Seventh Amendment, effective September 1, 2003, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (21)
10.21   Securities Purchase Agreement dated December 12, 2003 by and between Contango Oil & Gas Company and the Purchasers Named Therein. (19)
10.22   Freeport LNG Development, L.P. Amended and Restated Limited Partnership Agreement dated February 27, 2003. (20)
10.23   Partnership Purchase Agreement among Contango Sundance, Inc., Contango Oil & Gas, Cheniere LNG, Inc. and Cheniere Energy, Inc. dated March 1, 2003. (20)
10.24   First Amendment, dated December 19, 2003, to Freeport LNG Development, L.P. Amended and Restated Limited Partnership Agreement dated February 27, 2003. (20)
10.25   Eighth Amendment, effective February 13, 2004, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (22)
10.26   Ninth Amendment, effective July 29, 2004, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. †
14.1     Code of Ethics. (17)
21.1     List of Subsidiaries. †
23.1     Consent of W.D. Von Gonten & Co. †
31.1     Certification required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934. †
32.1     Certification pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. †

Filed herewith.
1. Filed as an exhibit to the Company’s Form 10-SB Registration Statement, as filed with the Securities and Exchange Commission on October 16, 1998.
2. Filed as an exhibit to the Company’s Form 10-QSB for the quarter ended December 31, 1999, as filed with the Securities and Exchange Commission on November 11, 1999.
3. Filed as an exhibit to the Company’s Form 10-QSB for the quarter ended December 31, 1999, as filed with the Securities and Exchange Commission on February 14, 2000.
4. Filed as an exhibit to the Company’s report on Form 8-K, dated August 24, 2000, as filed with the Securities and Exchange Commission of September 8, 2000.
5. Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2000, as filed with the Securities and Exchange Commission on September 27, 2000.
6. Filed as an exhibit to the Company’s report on Form 8-K, dated September 27, 2000, as filed with the Securities and Exchange Commission on October 3, 2000.
7. Filed as an exhibit to the Company’s report on Form 8-K, dated December 1, 2000, as filed with the Securities and Exchange Commission on December 15, 2000.
8. Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2001, as filed with the Securities and Exchange Commission on September 21, 2001.
9. Filed as an exhibit to the Company’s report on Form 8-K, dated January 4, 2002, as filed with the Securities and Exchange Commission on January 8, 2002.
10. Filed as an exhibit to the Company’s Form 10-QSB for the quarter ended March 31, 2002, as filed with the Securities and Exchange Commission on February 14, 2002.
11. Filed as an exhibit to the Company’s report filed on Form 10-QSB for the quarter ended March 31, 2002, dated May 2, 2002, as filed with the Securities and Exchange Commission.
12. Filed as an exhibit to the Company’s Form 10-QSB/A for the quarter ended December 31, 1999, as filed with the Securities and Exchange Commission on June 4, 2002.
13. Filed as an exhibit to the Company’s Registration Statement on Form S-1 (Registration No. 333-89900) as filed with the Securities and Exchange Commission on June 14, 2002.
14. Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2002, as filed with the Securities and Exchange Commission on September 26, 2002.
15. Filed as an exhibit to the Company’s report filed on Form 10-QSB for the quarter ended December 31, 2002, dated November 14, 2002, as filed with the Securities and Exchange Commission.
16. Filed as an exhibit to the Company’s report on Form 8-K, dated June 17, 2003, 2002, as filed with the Securities and Exchange Commission on June 18, 2003.
17. Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2003, as filed with the Securities and Exchange Commission on September 22, 2003.

 

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18. Filed as an exhibit to the Company’s report filed on Form 10-Q for the quarter ended September 30, 2003, dated November 12, 2003, as filed with the Securities and Exchange Commission.
19. Filed as an exhibit to the Company’s report on Form 8-K, dated December 12, 2003, as filed with the Securities and Exchange Commission on December 17, 2003.
20. Filed as an exhibit to the Company’s report on Form 8-K, dated December 19, 2003, as filed with the Securities and Exchange Commission on December 23, 2003.
21. Filed as an exhibit to the Company’s report filed on Form 10-Q for the quarter ended December 31, 2003, dated February 13, 2004, as filed with the Securities and Exchange Commission.
22. Filed as an exhibit to the Company’s report filed on Form 10-Q for the quarter ended March 31, 2004, dated May 12, 2004, as filed with the Securities and Exchange Commission.

 

(c) Reports on Form 8-K:

 

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

 

Form 8-K, event date June 18, 2004 (Items 5 and 7), reporting that the Federal Energy Regulatory Commission issued an Order under Section 3 of the Natural Gas Act authorizing Freeport LNG Development, LP to site, construct and operate a Liquefied Natural Gas Receiving Terminal in Freeport, Brazoria County, Texas, as filed on June 21, 2004.

 

Form 8-K, event date July 6, 2004 (Items 5 and 7), announcing that Freeport LNG Development, L.P finalized its transaction with ConocoPhillips for the construction and use of a proposed liquefied natural gas receiving terminal in Quintana, Brazoria County, Texas. ConocoPhillips acquired 1 billion cubic feet per day of regasification capacity in the terminal, obtained a 50 percent interest in the general partner managing the venture and will provide substantial construction funding to the venture, as filed on July 6, 2004.

 

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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 Financial Officer (principal executive officer and principal financial officer)   

Vice President and Controller

(principal accounting 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


  Chairman of the Board   September 27, 2004

Kenneth R. Peak

       

/s/ JAY D. BREHMER


  Director   September 27, 2004

Jay D. Brehmer

       

/s/ JOSEPH S. COMPOFELICE


  Director   September 27, 2004

Joseph S. Compofelice

       

/s/ DARRELL W. WILLIAMS


  Director   September 27, 2004

Darrell W. Williams

       

 

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

     Page

Report of Independent Certified Public Accountants

   F-2

Consolidated Balance Sheets, June 30, 2004 and 2003

   F-3

Consolidated Statements of Operations for the Years Ended June 30, 2004, 2003 and 2002

   F-5

Consolidated Statements of Cash Flows for the Years Ended June 30, 2004, 2003 and 2002

   F-6

Consolidated Statements of Stockholders’ Equity for the Years Ended June 30, 2004, 2003 and 2002

   F-7

Notes to Consolidated Financial Statements

   F-8

Supplemental Oil and Gas Disclosures

   F-21

Quarterly Results of Operations

   F-25

 

F-1


Table of Contents

REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

 

To the Stockholders 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, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended June 30, 2004. 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 of the Public Company Accounting Oversight Board (United States). 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, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2004, in conformity with accounting principles generally accepted in the United States of America.

 

GRANT THORNTON LLP

 

Houston, Texas

September 10, 2004

 

F-2


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

ASSETS

 

     June 30,

 
     2004

    2003

 

CURRENT ASSETS:

                

Cash and cash equivalents

   $ 396,753     $ 219,242  

Accounts receivable, net

     4,715,748       6,039,779  

Marketable equity securities

     —         676,500  

Other

     139,778       96,115  
    


 


Total current assets

     5,252,279       7,031,636  
    


 


PROPERTY, PLANT AND EQUIPMENT:

                

Natural gas and oil properties, successful efforts method of accounting:

                

Proved properties

     54,850,979       55,125,109  

Unproved properties, not being amortized

     7,540,678       3,065,188  

Furniture and equipment

     184,508       126,388  

Accumulated depreciation, depletion and amortization

     (27,282,035 )     (21,574,673 )
    


 


Total property, plant and equipment

     35,294,130       36,742,012  
    


 


OTHER ASSETS:

                

Cash held by affiliates

     779,361       784,656  

Investment in Freeport LNG project

     2,333,333       850,000  

Investment in NOSR project

     —         75,000  

Investment in Contango Venture Capital Corporation

     500,000       —    

Deferred income tax asset

     1,188,407       568,024  

Facility fee

     157,579       177,500  

Other

     5,822       76,112  
    


 


Total other assets

     4,964,502       2,531,292  
    


 


TOTAL ASSETS

   $ 45,510,911     $ 46,304,940  
    


 


 

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

 

F-3


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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

LIABILITIES AND SHAREHOLDERS’ EQUITY  
     June 30,

 
     2004

    2003

 

CURRENT LIABILITIES:

                

Accounts payable

   $ 810,360     $ 681,425  

Accrued exploration and development

     950,175       1,011,098  

Income taxes payable

     240,758       734,312  

Price hedge contracts

     —         58,171  

Short term hedge payable

     —         102,486  

Other accrued liabilities

     219,282       229,937  

Current portion of long-term debt

     —         5,890,000  
    


 


Total current liabilities

     2,220,575       8,707,429  
    


 


LONG-TERM DEBT

     7,089,000       16,460,000  

ASSET RETIREMENT OBLIGATION

     84,805       191,664  

DEFERRED CREDITS

     —         208,333  

STOCKHOLDERS’ EQUITY:

                

Convertible preferred stock, 8%, Series A, $0.04 par value, 5,000 shares authorized, 2,500 shares issued and outstanding at June 30, 2003, liquidation preference of $1,000 per share

     —         100  

Convertible preferred stock, 8%, Series B, $0.04 par value, 10,000 shares authorized, 5,000 shares issued and outstanding at June 30, 2003, liquidation preference of $1,000 per share

     —         200  

Convertible preferred stock, 6%, Series C, $0.04 par value, 4,000 shares authorized, 1,600 shares issued and outstanding at June 30, 2004, liquidation preference of $5,000 per share

     64       —    

Common stock, $0.04 par value, 50,000,000 shares authorized, 14,885,700 issued and 12,310,700 outstanding at June 30, 2004, 11,871,076 issued and 9,296,076 shares issued and outstanding at June 30, 2003

     595,428       473,399  

Additional paid-in capital

     29,979,965       21,803,090  

Treasury stock at cost (2,575,000 shares)

     (6,180,000 )     (6,180,000 )

Retained earnings

     11,721,074       4,640,725  
    


 


Total stockholders’ equity

     36,116,531       20,737,514  
    


 


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $ 45,510,911     $ 46,304,940  
    


 


 

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

 

F-4


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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

 

     Year Ended June 30,

 
     2004

    2003

    2002

 

REVENUES:

                        

Natural gas and oil sales

   $ 27,629,814     $ 33,919,126     $ 23,901,995  

Gain (loss) from hedging activities

     58,171       (5,708,958 )     5,016,173  
    


 


 


Total revenues

     27,687,985       28,210,168       28,918,168  
    


 


 


EXPENSES:

                        

Operating expenses

     3,888,185       5,736,454       3,904,541  

Exploration expenses

     9,873,164       17,922,116       2,694,425  

Depreciation, depletion and amortization

     6,989,428       8,787,794       8,593,635  

Impairment of natural gas and oil properties

     42,995       181,610       527,150  

General and administrative expense

     2,695,592       2,063,503       2,901,566  
    


 


 


Total expenses

     23,489,364       34,691,477       18,621,317  
    


 


 


INCOME (LOSS) FROM OPERATIONS

     4,198,621       (6,481,309 )     10,296,851  

Interest expense

     (362,127 )     (710,587 )     (285,159 )

Interest income

     38,182       30,359       194,905  

Gain on sale of marketable securities

     710,322       451,500       —    

Gain on sale of assets and other

     7,171,704       39,230       373,539  
    


 


 


INCOME (LOSS) BEFORE INCOME TAXES

     11,756,702       (6,670,807 )     10,580,136  

(Provision) benefit for income taxes

     (4,056,353 )     2,334,782       (4,003,154 )
    


 


 


NET INCOME (LOSS)

     7,700,349       (4,336,025 )     6,576,982  

Preferred stock dividends

     620,000       600,000       600,000  
    


 


 


NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK

   $ 7,080,349     $ (4,936,025 )   $ 5,976,982  
    


 


 


NET INCOME (LOSS) PER SHARE:

                        

Basic

   $ 0.68     $ (0.54 )   $ 0.55  
    


 


 


Diluted

   $ 0.58     $ (0.54 )   $ 0.48  
    


 


 


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:

                        

Basic

     10,484,078       9,129,169       10,841,665  
    


 


 


Diluted

     13,279,862       9,129,169       13,711,597  
    


 


 


 

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

 

F-5


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     Year Ended June 30,

 
     2004

    2003

    2002

 

CASH FLOWS FROM OPERATING ACTIVITIES:

                        

Net income (loss)

   $ 7,700,349     $ (4,336,025 )   $ 6,576,982  

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

                        

Depreciation, depletion and amortization

     6,989,428       8,787,794       8,593,635  

Impairment of natural gas and oil properties

     42,995       181,610       527,150  

Exploration expenditures

     6,073,120       6,351,117       2,236,515  

Provision (benefit) for deferred income taxes

     (620,383 )     (4,345,888 )     598,616  

Gain on sale of assets and other

     (7,882,026 )     (490,730 )     (373,539 )

Unrealized (gain) loss on hedges

     (58,171 )     (64,423 )     1,014,074  

Stock-based compensation

     339,005       141,723       56,808  

Changes in operating assets and liabilities:

                        

(Increase) decrease in accounts receivable and others

     1,272,822       (819,326 )     74,186  

Increase in marketable equity securities

     —         (225,000 )     —    

Decrease (increase) in prepaid insurance

     (22,301 )     118,713       1,901  

Increase (decrease) in accounts payable

     (391,551 )     (594,933 )     1,496,307  

Increase (decrease) in other accrued liabilities

     11,652       (211,585 )     311,768  

Increase (decrease) in taxes payable

     (493,554 )     (306,476 )     1,040,788  

Other

     158,338       (92,053 )     317,368  
    


 


 


Net cash provided by operating activities

     13,119,723       4,094,518       22,472,559  
    


 


 


CASH FLOWS FROM INVESTING ACTIVITIES:

                        

Natural gas and oil exploration and development expenditures

     (12,150,210 )     (8,595,940 )     (7,743,984 )

Decrease (increase) in net investment in affiliates

     5,295       850,000       (1,612,860 )

Investment in Freeport LNG Project

     (1,483,333 )     (100,000 )     (750,000 )

Purchase of marketable equity securities

     (375,000 )     —         —    

Proceeds from sales of marketable equity securities

     1,761,822       —         —    

Investment in Contango Capital Partnership Management, LLC

     (500,000 )     —         —    

Additions to furniture and equipment

     (58,120 )     (16,560 )     (15,854 )

Decrease (increase) in advances to operators

     157,350       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

     7,761,098       —         261,448  
    


 


 


Net cash used in investing activities

     (4,881,098 )     (9,611,704 )     (33,621,806 )
    


 


 


CASH FLOWS FROM FINANCING ACTIVITIES:

                        

Borrowings under credit facility

     22,229,028       29,670,000       31,050,000  

Repayments under credit facility

     (37,490,028 )     (26,270,000 )     (12,100,000 )

Proceeds from preferred equity issuances

     7,554,614       —         —    

Purchase of treasury shares

     —         —         (6,180,000 )

Preferred stock dividends

     (620,000 )     (600,000 )     (600,000 )

Repurchase/cancellation of stock options and warrants

     (757,498 )     —         —    

Proceeds from exercised options and warrants

     1,075,769       433,333       225,000  

Debt issue costs

     (52,999 )     (223,750 )     (105,250 )
    


 


 


Net cash provided (used) by financing activities

     (8,061,114 )     3,009,583       12,289,750  
    


 


 


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     177,511       (2,507,603 )     1,140,503  

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

     219,242       2,726,845       1,586,342  
    


 


 


CASH AND CASH EQUIVALENTS, END OF PERIOD

   $ 396,753     $ 219,242     $ 2,726,845  
    


 


 


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

                        

Cash paid for taxes

   $ 4,781,239     $ 2,549,788     $ 2,355,000  
    


 


 


Cash paid for interest

   $ 386,743     $ 711,808     $ 265,664  
    


 


 


 

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

 

F-6


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

 

     Preferred Stock

    Common Stock

  

Paid-in

Capital


   

Treasury

Stock


   

Retained

Earnings


   

Total

Stockholders’

Equity


 
     Shares

    Amount

    Shares

    Amount

        

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  

Exercise of stock options and warrants

   —         —       518,750       20,750      1,055,019       —         —         1,075,769  

Tax benefit from exercise of stock options

   —         —       —         —        86,778       —         —         86,778  

Expense of stock options

   —         —       —         —        339,005       —         —         339,005  

Cashless exercise of stock options and warrants

   —         —       359,510       15,824      (15,824 )     —         —         —    

Repurchase/cancellation of stock options and warrants

   —         —       —         —        (757,498 )     —         —         (757,498 )

Conversion of Series A preferred stock and Series B preferred stock to common stock

   (7,500 )     (300 )   2,136,364       85,455      (85,155 )     —         —         —    

Issuance of Series C preferred stock

   1,600       64     —         —        7,554,550       —         —         7,554,614  

Net income

   —         —       —         —        —         —         7,700,349       7,700,349  

Preferred stock dividends

   —         —       —         —        —         —         (620,000 )     (620,000 )
    

 


 

 

  


 


 


 


Balance at June 30, 2004

   1,600     $ 64     12,310,700     $ 595,428    $ 29,979,965     $ (6,180,000 )   $ 11,721,074     $ 36,116,531  
    

 


 

 

  


 


 


 


 

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

 

F-7


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1. Organization and Business

 

Contango is an independent natural gas and oil company engaged in the exploration, production and acquisition of natural gas and oil in the United States. The Company’s primary source of production is currently in south Texas. It also own leases and conduct exploration activities offshore in the Gulf of Mexico, owns a 10% partnership interest in Freeport LNG Development, L.P.(“Freeport LNG”), which is developing a 1.5 Bcf per day LNG receiving terminal in Freeport, Texas and a 32% interest in Contango Capital Partnership Management, LLC, which was formed to invest in the alternative energy venture capital market. The Company’s common stock trades on the American Stock Exchange under the symbol “MCF”.

 

2. Summary of Significant Accounting Policies

 

The application of generally accepted accounting principles involves certain assumptions, judgments, choices and estimates that affect reported amounts of assets, liabilities, revenues and expenses. Thus, the application of these principles can result in varying results from company to company. Contango’s critical accounting principles, which are described below, relate to the successful efforts method for costs related to natural gas and oil activities, consolidation principles, accounting for financial instruments and stock options.

 

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, 2004 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, 2004 and 2003, the Company had cash and cash equivalents of $396,753 and $219,242, respectively. 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 related 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 4 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 differences between

 

F-8


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

the tax basis 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.

 

Fair Value of Financial Instruments. The carrying amounts of the Company’s short-term financial instruments, including cash equivalents, trade accounts receivable and trade accounts payable, approximate their fair values based on the short maturities of those instruments. The Company’s long-term debt is variable rate debt and, as such, approximates fair value, as interest rates are variable based on prevailing market rates.

 

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

 

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

 

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

 

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

 

F-9


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

of their profits and losses among the owners. Accordingly, the Company determines its income or losses from the ventures based on a hypothetical liquidation determination of how increases or decreases in the book value of the ventures’ net assets will ultimately affect the cash payments to the Company in the event of dissolution.

 

During the quarter ended December 31, 2002, both Republic Exploration and Magnolia Offshore Exploration completed exploration activities to fully expend the Company’s initial cash contributions to the ventures thereby triggering a change in profit and loss allocations. This triggering event earned the other partners in Republic Exploration and Magnolia Offshore Exploration the right to receive their proportionate share of the Company’s initial investment in Republic Exploration and Magnolia Offshore Exploration. As such, the Company proportionately consolidated 33.3% of Republic Exploration’s and 50.0% of Magnolia Offshore Exploration’s net assets as of December 31, 2002, as opposed to 100% of each ventures’ net assets as of September 30, 2002. The reduction of the Company’s ownership in the net assets of Republic Exploration and Magnolia Offshore Exploration resulted in a non-cash exploration expense of approximately $4.2 million and approximately $200,000, respectively. The Company’s cash contributions to Contango Offshore Exploration during the year ended June 30, 2004 that were expended for geological and geophysical data resulted in an approximate $2.5 million exploration expense. The Company’s proportionate share of the ventures’ cash balances is classified as other long-term assets since it is expected those funds will be expended for their intended purposes.

 

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

 

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

 

Investment in Contango Capital in which Contango has 32% ownership is accounted for using the equity method. Under the equity method, only Contango’s investment in and amounts due to and from the equity investee are included in the consolidated balance sheet.

 

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

 

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

 

  The equity investors (if any) do not have a controlling financial interest

 

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

 

F-10


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

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

 

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

 

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

 

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

 

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

 

The Company has determined that the fair value method is preferable to the intrinsic value method previously applied. During the years ended June 30, 2004, 2003 and 2002, the Company recorded a charge of $339,005, $134,431 and $29,796 to general and administrative expense, respectively. Because compensation expense is recognized over a vesting period, the effect of applying the fair value method in the initial years of implementation may not be representative of the effects on net income (loss) that will be reported in future years.

 

Derivative Instruments and Hedging Activities. Contango previously has 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 are 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.

 

F-11


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

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

 

     Year Ended June 30,

 
     2004

   2003

    2002

 

Mark-to-market reversal of prior period unrealized recognized loss (gain)

   $ 58,171    $ 125,674     $ (888,400 )

Net cash received (paid) from swap settlements/options purchased

     —        (5,776,461 )     6,030,247  

Mark-to-market loss unrealized

     —        (58,171 )     (125,674 )
    

  


 


Gain (loss) from hedging activities

   $ 58,171    $ (5,708,958 )   $ 5,016,173  
    

  


 


 

Although the Company’s hedging transactions generally have been designed as economic hedges for a portion of future natural gas and oil production, the Company elected not to designate the derivative instruments as “hedges” under SFAS 133. As a result, gains and losses, representing changes in these derivative instruments’ mark-to-market fair values, were recognized in the Company’s earnings. The Company had no open commodity derivative contracts at June 30, 2004.

 

Asset Retirement Obligation. The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”, (“SFAS 143”), as of July 1, 2002. SFAS requires the Company to record the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. 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. Activities related to the Company’s ARO during the year ended June 30, 2004 and 2003 are as follows:

 

     Year Ended June 30,

     2004

    2003

Initial ARO as of July 1

   $ 191,664     $ 172,638

Liabilities incurred during period

     6,987       9,666

Liabilities settled during period

     (129,336 )     —  

Accretion expense

     15,490       9,360
    


 

Balance of ARO as of June 30

   $ 84,805     $ 191,664
    


 

 

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.

 

F-12


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

4. 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, 2004, 2003 and 2002 is presented below:

 

     Year Ended June 30, 2004

 
    

Net

Income


    Shares

    Per
Share


 

Basic:

                      

Net income attributable to common stock

   $ 7,080,349     10,484,078     $ 0.68  
                  


Effect of Potential Dilutive Securities:

                      

Stock options and warrants

     —       795,812          

Series A preferred stock

     117,777     592,896          

Series B preferred stock

     235,556     673,746          

Series C preferred stock

     266,667     733,330          
    


 

       

Diluted:

                      

Net income

   $ 7,700,349     13,279,862     $ 0.58  
    


 

 


Anti-dilutive Securities:

                      

Shares assumed not issued from options to purchase common shares as the exercise price was above the average market price for the period

   $ —       301,500     $ 6.81  
     Year Ended June 30, 2003

 
    

Net

Income


    Shares

    Per
Share


 

Basic:

                      

Net loss attributable to common stock

   $ (4,936,025 )   9,129,169     $ (0.54 )
                  


Effect of Potential Dilutive Securities:

                      

Stock options and warrants

     (a )   (a )        

Series A preferred stock

     (a )   (a )        

Series B preferred stock

     (a )   (a )        
    


 

       

Diluted:

                      

Net loss

   $ (4,936,025 )   9,129,169     $ (0.54 )
    


 

 


Anti-dilutive Securities:

                      

Shares assumed not issued from options to purchase common shares as the exercise price was above the average market price for the period

   $ —       548,500     $ 4.04  
     Year Ended June 30, 2002

 
    

Net

Income


    Shares

    Per
Share


 

Basic:

                      

Net income attributable to common stock

   $ 5,976,982     10,841,665     $ 0.55  
                  


Effect of Potential Dilutive Securities:

                      

Stock options and warrants

     —       733,569          

Series A preferred stock

     200,000     1,000,000          

Series B preferred stock

     400,000     1,136,363          
    


 

       

Diluted:

                      

Net income

   $ 6,576,982     13,711,597     $ 0.48  
    


 

 


Anti-dilutive Securities:

                      

Shares assumed not issued from options to purchase common shares as the exercise price was above the average market price for the period

   $ —       610,000     $ 3.92  

(a) Anti-dilutive.

 

F-13


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

5. 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,

 
     2004

    2003

    2002

 

Provision (benefit) at statutory tax rate

   $ 4,114,846     35.0 %   $ (2,334,782 )   35.0 %   $ 3,703,048     35.0 %

State income tax provision (benefit)

     (103,409 )   -0.8 %     —       —         450,000     4.3 %

Federal benefit of state income taxes

     36,193     0.3 %     —       —         (157,500 )   -1.5 %

Other

     8,723     —         —       —         7,606     —    
    


 

 


 

 


 

Income tax provision (benefit)

   $ 4,056,353     34.5 %   $ (2,334,782 )   35.0 %   $ 4,003,154     37.8 %
    


 

 


 

 


 

 

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

 

     Year Ended June 30,

     2004

    2003

    2002

Current:

                      

Federal

   $ 4,693,367     $ 2,903,815     $ 2,961,538

State

     (103,409 )     —         450,000
    


 


 

Total

   $ 4,589,958     $ 2,903,815     $ 3,411,538
    


 


 

Deferred:

                      

Federal

   $ (533,605 )   $ (5,238,597 )   $ 591,616

State

     —         —         —  
    


 


 

Total

   $ (533,605 )   $ (5,238,597 )   $ 591,616
    


 


 

Total:

                      

Federal

   $ 4,159,762     $ (2,334,782 )   $ 3,553,154

State

     (103,409 )     —         450,000
    


 


 

Total

   $ 4,056,353     $ (2,334,782 )   $ 4,003,154
    


 


 

 

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

 

     Year Ended June 30,

 
     2004

   2003

    2002

 

Deferred tax asset:

                       

Capital loss carryforwards and other

   $ —      $ 1,784,638     $ —    

Temporary basis differences in natural gas and oil properties and others

     1,188,407      —         —    
    

  


 


     $ 1,188,407    $ 1,784,638     $ —    
    

  


 


Deferred tax liability:

                       

Temporary basis differences in natural gas and oil properties and others

     —        (1,216,614 )     (3,777,864 )
    

  


 


Net Deferred tax asset (liability)

   $ 1,188,407    $ 568,024     $ (3,777,864 )
    

  


 


 

F-14


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

6. 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.

 

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.

 

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 certain south Texas properties at a cost of approximately $2.6 million. This acquisition was funded with availability under the Company’s credit facility.

 

7. Sale of Properties

 

In September 2003, the Company completed the sale of certain reserves in Brooks County, Texas for $5.0 million and recorded a gain of $984,000 for the year ended June 30, 2004. Proved reserves were 1.5 Bcfe and accounted for approximately $5.0 million of the Company’s discounted present value at 10% per annum as of June 30, 2003.

 

In December 2003, Contango and Republic Exploration sold their producing Gulf of Mexico leases for approximately $12.0 million. As a result of this sale, Contango recorded a gain of approximately $6.2 million for the year ended June 30, 2004. Properties included in the sale were Eugene Island 110, Grand Isle 28 and High Island 25-L. Contango received approximately $3.7 million in cash proceeds for its portion of the sale. Republic Exploration received cash proceeds of approximately $8.3 million for its portion of the sale. Republic Exploration subsequently made distributions of $3.0 million to its members, including a $1.0 million distribution to Contango.

 

8. Long-Term Debt

 

On June 29, 2001, Contango replaced its existing line of credit with a three year, secured, 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. In February 2004, the borrowing base was redetermined at $25 million and was again redetermined in September 2004 at $21.0 million. Tranche A provides for a borrowing base of $19.0 million and matures on June 29, 2006. This amount reduces by $595,000 per month the first day of each month beginning November 1, 2004. Borrowings under Tranche A bear interest, at our option, at either (i) LIBOR plus two percent (2%) or (ii) the bank’s base rate plus one-fourth percent (1/4%) per annum. Additionally, we pay a quarterly commitment fee of three-eighths percent (3/8%) per annum on the average availability of Tranche A. Tranche B provides for a borrowing base of $2.0 million and matures on April 1, 2005. Borrowings under Tranche B will reduce by $595,000 per month the first day of each month following the month in which Tranche B is funded, with the final reduction on April 1, 2005. Further, any amounts borrowed and repaid under Tranche B cannot be reborrowed. Borrowings under Tranche B bear interest, at the Company’s option, at either (i) LIBOR plus three percent (3%) or (ii) the bank’s base rate plus three-quarters percent (3/4%) per annum. Additionally, we pay a quarterly commitment fee of one-half percent (1/2%) per annum on the average availability under Tranche B. As of June 30, 2004, the Company had $7,089,000 outstanding under Tranche A and no borrowings under Tranche B.

 

F-15


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

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.

 

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

 

     June 30,

 
     2004

   2003

 

Outstanding under line of credit

   $ 7,089,000    $ 22,350,000  

Current portion of long term-debt

     —        (5,890,000 )
    

  


Total long-term debt

   $ 7,089,000    $ 16,460,000  
    

  


 

As of June 30, 2004 and 2003, the Company was in compliance with its financial covenants, ratios and other provisions of the credit facility.

 

9. Commitments and Contingencies

 

Contango leases its office space and certain other equipment. As of June 30, 2004, minimum future lease payments are as follows:

 

Fiscal Years Ending June 30,

      

2005

     122,316

2006

     120,866

2007

     39,879

Thereafter

     —  
    

Total

   $ 283,061
    

 

The amount incurred under operating leases during the years ended June 30, 2004, 2003 and 2002 was $83,596, $88,404 and $80,009, respectively.

 

10. Stockholders’ 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.

 

Preferred Stock. The Company’s Board of Directors has authorized 5,000,000 shares of preferred stock, of which 1,600 shares of Series C convertible preferred stock was issued and outstanding as of June 30, 2004.

 

On December 12, 2003, Contango sold 1,600 shares of its Series C convertible cumulative preferred stock (the “Series C Preferred Stock”) to a group of private institutional investors for gross proceeds of $8.0 million. Series C Preferred Stock ranks prior to the Company’s common stock (and any other junior stock) with respect to the payment of dividends or distributions and upon liquidation, dissolution, winding-up or otherwise and is junior to the

 

F-16


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

Company’s Series A senior convertible cumulative preferred stock and Series B senior convertible cumulative preferred stock. Holders of Series C Preferred Stock are entitled to receive quarterly dividends at a dividend rate equal to 6% per annum if paid in cash on a current quarterly basis or otherwise at a rate of 7.5% per annum if not paid on a current quarterly basis or if paid in shares of Series C Preferred Stock, in each case, computed on the basis of $5,000 per share. Holders of Series C Preferred Stock may, at their discretion, elect to convert such shares to shares of the Company’s common stock at a conversion price of $6.00 per share. After June 12, 2005, upon the occurrence of certain events, the Company may elect to convert all of the outstanding shares of Series C Preferred Stock into Contango common stock. The Company has filed a shelf registration with the Securities and Exchange Commission, which is effective, covering the 1,333,328 common shares issuable upon conversion of the Series C preferred stock.

 

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

 

11. Repurchase of Certain Stock Options and Warrants

 

In September 2003, Contango paid $757,498 to certain related parties and cancelled certain stock options and warrants to purchase 336,666 shares of Contango common stock exercisable at $2.00 per share. These stock options and warrants were fully vested. Options to purchase an additional 33,334 shares of Contango common stock were also cancelled. In accordance with the terms of these stock options, vesting would never occur. Contango paid $2.25 per option. The fair market value of each option at the date of cancellation, using the Black-Scholes options-pricing model, was estimated at $2.69. Assumptions used in this estimate were: (i) risk-free interest rate of 3.28 percent; (ii) expected volatility of 36 percent; (iii) expected dividend yield of zero percent; and (iv) underlying stock price at the date of cancellation of $4.55.

 

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, 2004, options under the Option Plan to acquire 1,098,437 shares of common stock have been granted at prices between $2.44 and $7.75 per share and were outstanding.

 

In addition to grants made under the Option Plan, the Company has granted other 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, 2004, other options to acquire 180,584 shares of common stock have been granted at prices between $2.00 and $5.87 per share and were outstanding.

 

F-17


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

A summary of the status of the plans as of June 30, 2004, 2003 and 2002, and changes during the fiscal years then ended, is presented in the table below:

 

     Year Ended June 30,

     2004

   2003

   2002

     Shares
Under
Options


    Weighted
Average
Exercise
Price


   Shares
Under
Options


    Weighted
Average
Exercise
Price


   Shares
Under
Options


    Weighted
Average
Exercise
Price


Outstanding, beginning of year

     1,280,334     $ 2.98      1,210,334     $ 2.85      1,015,334     $ 2.89

Granted

     465,000     $ 6.06      292,500     $ 3.35      255,000     $ 2.60

Exercised

     (113,479 )   $ 2.79      (130,001 )   $ 2.27      (37,500 )   $ 2.00

Cancelled

     (352,834 )   $ 2.06      (92,499 )   $ 3.43      (22,500 )   $ 3.40
    


        


        


     

Outstanding, end of year

     1,279,021     $ 4.37      1,280,334     $ 2.98      1,210,334     $ 2.85
    


        


        


     

Exercisable, end of year

     766,187     $ 4.05      851,667     $ 2.97      795,334     $ 2.76
    


        


        


     

Available for grant, end of year

     1,170,583              1,597,749              1,794,750        
    


        


        


     

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

   $ 1.56            $ 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, 2004, 2003 and 2002, respectively: (i) risk-free interest rate of 3.88 percent, 3.14 percent and 3.98 percent; (ii) expected lives of five years for the Option Plan and other options; (iii) expected volatility of 26 percent, 27 percent and 20 percent; and (iv) expected dividend yield of zero percent.

 

The following table summarizes information about options that were outstanding at June 30, 2004:

 

     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
Outstanding
Options


   Weighted
Average
Exercise
Price


$2.00 - $2.99

   152,855    5.8    $ 2.41    82,188    $ 2.36

$3.00 - $3.99

   393,666    3.0    $ 3.15    279,666    $ 3.14

$4.00 - $4.99

   421,000    2.9    $ 4.45    293,833    $ 4.39

$5.00 - $5.99

   10,000    1.6    $ 5.56    10,000    $ 5.56

$6.00 - $6.99

   291,000    4.9    $ 6.78    97,000    $ 6.78

$7.00 - $7.99

   10,500    4.8    $ 7.75    3,500    $ 7.75
    
              
      
     1,279,021    3.7    $ 4.37    766,187    $ 4.05
    
              
      

 

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, 2004, 2003 and 2002, the Company recorded stock option expense of $339,005, $134,431 and $29,796, respectively.

 

F-18


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

13. Warrants

 

As of June 30, 2004, the Company had outstanding warrants to purchase 687,500 shares of the Company’s common stock. All warrants were exercisable at June 30, 2004. 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, 2004, 2003 and 2002, and changes during the fiscal years then ended, is presented in the table below:

 

     Year Ended June 30,

     2004

   2003

   2002

     Number of
Shares
Under
Outstanding
Warrants


    Weighted
Average
Exercise
Price


   Number of
Shares
Under
Outstanding
Warrants


    Weighted
Average
Exercise
Price


   Number of
Shares
Under
Outstanding
Warrants


    Weighted
Average
Exercise
Price


Outstanding, beginning of year

   1,640,185     $ 2.16    1,840,185     $ 2.14    2,040,185     $ 2.13

Exercised

   (890,185 )   $ 2.00    (200,000 )   $ 2.00    (75,000 )   $ 2.00

Cancelled

   (62,500 )   $ 2.00    —       $ —      (125,000 )   $ 2.00
    

        

        

     

Outstanding, end of year

   687,500     $ 2.39    1,640,185     $ 2.16    1,840,185     $ 2.14
    

        

        

     

Exercisable, end of year

   687,500     $ 2.39    1,640,185     $ 2.16    1,840,185     $ 2.14
    

 

  

 

  

 

 

The following table summarizes information about warrants that were outstanding at June 30, 2004:

 

    

Warrants Outstanding

and Exercisable


Exercise Price


   Number of
Shares
Under
Outstanding
Warrants


   Weighted
Average
Remaining
Contractual
Life (Years)


$2.00

   562,500    0.2

$4.12

   125,000    1.4
    
    
     687,500    0.4
    
    

 

14. Investment in Freeport LNG

 

In March 2003, Contango 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 1.5 billion cubic feet per day LNG receiving terminal in Freeport, Texas. The $2.3 million cost to acquire the Company’s 10% limited partnership interest was paid as of June 30, 2004, including a final payment of $0.4 million paid in June 2004 upon receipt of Federal Energy Regulatory Commission (“FERC”) approval for the project.

 

In June 2003, Dow Chemical Company (“Dow”) signed an agreement with Freeport LNG for the potential long-term use of the receiving terminal. Under the agreement, Dow had regasification rights to 500 million cubic feet per day beginning with commercial start-up of the facility expected in 2007. On March 1, 2004, Freeport LNG and Dow entered into a 20-year Terminal Use Agreement providing for a firm commitment by Dow for the use of 250 million cubic feet per day of regasification capacity and an option to acquire an additional 250 million cubic feet per day of regasification capacity. Dow has exercised its rights to the full 500 million cubic feet per day of regasification capacity.

 

F-19


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

In June 2004, FERC issued an Order under Section 3 of the Natural Gas Act authorizing Freeport LNG to site, construct and operate a liquefied natural gas receiving terminal in Freeport, Texas.

 

Although we believe that a majority of the Freeport LNG financing will be provided by construction funding through ConocoPhillips, we anticipate that we will, from time-to-time, be required to provide funds to the project (see footnote 17, “Subsequent Events”). Moreover, if the plant’s capacity were to be expanded beyond its current anticipated 1.5 Bcf per day, we would likely be required to provide our pro rata 10% equity participation to help secure the funds required for expanding the plant’s capacity.

 

15. Gain on Sale of Marketable Securities

 

As part of the formation of Freeport LNG Development, L.P., Cheniere Energy, Inc. (“Cheniere”) granted Contango warrants to purchase 300,000 shares of Cheniere common stock. In June and September 2003, Contango exercised the warrants, purchasing 300,000 shares of Cheniere common stock. The Company sold the Cheniere common stock and reported a gain on the sale of marketable securities for the year ended June 30, 2004 of $710,322.

 

16. Related Party Transactions

 

The Company leases its corporate offices at 3700 Buffalo Speedway, Suite 960, Houston, Texas 77098. The agreement provides for a monthly rental of $9,970 per month through October 2006. Effective June 1, 2004, two of our directors began using one of the Company’s offices and certain common areas for activities unrelated to the Company for which they reimburse the Company $1,000 per month.

 

17. Subsequent Events

 

On July 1, 2004, private institutional investors elected to convert 200 of the 1,600 outstanding shares of the Company’s Series C convertible cumulative preferred stock into 166,666 shares of Contango common stock.

 

In July 2004, Freeport LNG finalized its transaction with ConocoPhillips for the construction and use of the proposed liquefied LNG receiving terminal in Freeport, Texas. ConocoPhillips acquired 1.0 billion cubic feet per day of regasification capacity in the terminal, purchased a 50% interest in the general partner managing the Freeport LNG project and will provide substantial construction funding to the venture. This construction funding will be non-recourse to Contango. Freeport LNG and the ConocoPhillips team continue to negotiate the engineering, procurement and construction contract for the terminal. The current management of Freeport LNG will remain in place and will oversee the commercial activities of the partnership, while ConocoPhillips will manage the construction of the facility and oversee its operations.

 

F-20


Table of Contents

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 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,

     2004

   2003

   2002

Property Acquisition Costs:

                    

Unproved

   $ 4,475,908    $ 972,658    $ 1,063,204

Proved

     —        2,602,551      23,449,488

Exploration costs

     6,923,762      19,194,281      7,138,690

Developmental costs

     983,933      —        —  
    
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